Downhole tool and method of use

ABSTRACT

A downhole tool suitable for use in a wellbore that includes a wedge mandrel having a distal end; a proximate end; an outer surface; and a flowbore. The tool includes a fingered member disposed around the wedge mandrel. The tool includes a ball seat insert disposed in the flowbore, as well as a support platform disposed in the flowbore.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation of U.S. Non-Provisional patentapplication Ser. No. 15/899,147, filed on Feb. 19, 2018, now issued asU.S. Pat. No. 10,480,147, which is a ‘bypass’ continuation of PCTApplication Ser. No. PCT/US17/62379, filed on Nov. 17, 2017, whichclaims priority to U.S. Provisional Patent Application Ser. No.62/423,620, filed on Nov. 17, 2016. The disclosure of each applicationis hereby incorporated herein by reference in its entirety for allpurposes.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND Field of the Disclosure

This disclosure generally relates to downhole tools and related systemsand methods used in oil and gas wellbores. More specifically, thedisclosure relates to a downhole system and tool that may be run into awellbore and useable for wellbore isolation, and methods pertaining tothe same. In particular embodiments, the downhole tool may be acomposite plug made of drillable materials. In other embodiments, thedownhole tool may have one or more metal components. Some components maybe made of a dissolvable material.

Background of the Disclosure

An oil or gas well includes a wellbore extending into a subterraneanformation at some depth below a surface (e.g., Earth's surface), and isusually lined with a tubular, such as casing, to add strength to thewell. Many commercially viable hydrocarbon sources are found in “tight”reservoirs, which means the target hydrocarbon product may not be easilyextracted. The surrounding formation (e.g., shale) to these reservoirsis typically has low permeability, and it is uneconomical to produce thehydrocarbons (i.e., gas, oil, etc.) in commercial quantities from thisformation without the use of drilling accompanied with fracingoperations.

Fracing is common in the industry and includes the use of a plug set inthe wellbore below or beyond the respective target zone, followed bypumping or injecting high pressure frac fluid into the zone. FIG. 1illustrates a conventional plugging system 100 that includes use of adownhole tool 102 used for plugging a section of the wellbore 106drilled into formation 110. The tool or plug 102 may be lowered into thewellbore 106 by way of workstring 105 (e.g., e-line, wireline, coiledtubing, etc.) and/or with setting tool 112, as applicable. The tool 102generally includes a body 103 with a compressible seal member 122 toseal the tool 102 against an inner surface 107 of a surrounding tubular,such as casing 108. The tool 102 may include the seal member 122disposed between one or more slips 109, 111 that are used to help retainthe tool 102 in place.

In operation, forces (usually axial relative to the wellbore 106) areapplied to the slip(s) 109, 111 and the body 103. As the settingsequence progresses, slip 109 moves in relation to the body 103 and slip111, the seal member 122 is actuated, and the slips 109, 111 are drivenagainst corresponding conical surfaces 104. This movement axiallycompresses and/or radially expands the compressible member 122, and theslips 109, 111, which results in these components being urged outwardfrom the tool 102 to contact the inner wall 107. In this manner, thetool 102 provides a seal expected to prevent transfer of fluids from onesection 113 of the wellbore across or through the tool 102 to anothersection 115 (or vice versa, etc.), or to the surface. Tool 102 may alsoinclude an interior passage (not shown) that allows fluid communicationbetween section 113 and section 115 when desired by the user. Oftentimesmultiple sections are isolated by way of one or more additional plugs(e.g., 102A).

Upon proper setting, the plug may be subjected to high or extremepressure and temperature conditions, which means the plug must becapable of withstanding these conditions without destruction of the plugor the seal formed by the seal element. High temperatures are generallydefined as downhole temperatures above 200° F., and high pressures aregenerally defined as downhole pressures above 7,500 psi, and even inexcess of 15,000 psi. Extreme wellbore conditions may also include highand low pH environments. In these conditions, conventional tools,including those with compressible seal elements, may become ineffectivefrom degradation. For example, the sealing element may melt, solidify,or otherwise lose elasticity, resulting in a loss the ability to form aseal barrier.

Before production operations commence, the plugs must also be removed sothat installation of production tubing may occur. This typically occursby drilling through the set plug, but in some instances the plug can beremoved from the wellbore essentially intact. A common problem withretrievable plugs is the accumulation of debris on the top of the plug,which may make it difficult or impossible to engage and remove the plug.Such debris accumulation may also adversely affect the relative movementof various parts within the plug. Furthermore, with current retrievingtools, jarring motions or friction against the well casing may causeaccidental unlatching of the retrieving tool (resulting in the toolsslipping further into the wellbore), or re-locking of the plug (due toactivation of the plug anchor elements). Problems such as these oftenmake it necessary to drill out a plug that was intended to beretrievable.

However, because plugs are required to withstand extreme downholeconditions, they are built for durability and toughness, which oftenmakes the drill-through process difficult. Even drillable plugs aretypically constructed of a metal such as cast iron that may be drilledout with a drill bit at the end of a drill string. Steel may also beused in the structural body of the plug to provide structural strengthto set the tool. The more metal parts used in the tool, the longer thedrilling operation takes. Because metallic components are harder todrill through, this process may require additional trips into and out ofthe wellbore to replace worn out drill bits.

The use of plugs in a wellbore is not without other problems, as thesetools are subject to known failure modes. When the plug is run intoposition, the slips have a tendency to pre-set before the plug reachesits destination, resulting in damage to the casing and operationaldelays. Pre-set may result, for example, because of residue or debris(e.g., sand) left from a previous frac. In addition, conventional plugsare known to provide poor sealing, not only with the casing, but alsobetween the plug's components. For example, when the sealing element isplaced under compression, its surfaces do not always seal properly withsurrounding components (e.g., cones, etc.).

Downhole tools are often activated with a drop ball that is flowed fromthe surface down to the tool, whereby the pressure of the fluid must beenough to overcome the static pressure and buoyant forces of thewellbore fluid(s) in order for the ball to reach the tool. Frac fluid isalso highly pressurized in order to not only transport the fluid intoand through the wellbore, but also extend into the formation in order tocause fracture. Accordingly, a downhole tool must be able to withstandthese additional higher pressures.

It is naturally desirable to “flow back,” i.e., from the formation tothe surface, the injected fluid, or the formation fluid(s); however,this is not possible until the previously set tool or its blockage isremoved. Removal of tools (or blockage) usually requires awell-intervention service for retrieval or drill-through, which is timeconsuming, costly, and adds a potential risk of wellbore damage.

The more metal parts used in the tool, the longer the drill-throughoperation takes. Because metallic components are harder to drill, suchan operation may require additional trips into and out of the wellboreto replace worn out drill bits.

In the interest of cost-saving, materials that react under certaindownhole conditions have been the subject of significant research inview of the potential offered to the oilfield industry. For example,such an advanced material that has an ability to degrade by mereresponse to a change in its surrounding is desirable because no, orlimited, intervention would be necessary for removal or actuation tooccur.

Such a material, essentially self-actuated by changes in its surrounding(e.g., the presence a specific fluid, a change in temperature, and/or achange in pressure, etc.) may potentially replace costly and complicateddesigns and may be most advantageous in situations where accessibilityis limited or even considered to be impossible, which is the case in adownhole (subterranean) environment.

It is highly desirable and economically advantageous to have controlsthat do not rely on lengthy and costly wirelines, hydraulic controllines, or coil tubings. Furthermore, in countless situations, asubterranean piece of equipment may need to be actuated only once, afterwhich it may no longer present any usefulness, and may even becomedisadvantageous when for instance the equipment must be retrieved byrisky and costly interventions.

In some instances, it may be advantageous to have a device (ball, tool,component, etc.) made of a material (of composition of matter)characterized by properties where the device is mechanically strong(hard) under some conditions (such as at the surface or at ambientconditions), but degrades, dissolves, breaks, etc. under specificconditions, such as in the presence of water-containing fluids likefresh water, seawater, formation fluid, additives, brines, acids andbases, or changes in pressure and/or temperature. Thus, after apredetermined amount of time, and after the desired operation(s) iscomplete, the formation fluid is ultimately allowed to flow toward thesurface.

It would be advantageous to configure a device (or a related activationdevice, such as a frac ball, or other component(s)) to utilize materialsthat alleviate or reduce the need for an intervention service. Thiswould save a considerable amount of time and expense. Therefore, thereis a need in the art for tools, devices, components, etc. to be of anature that does not involve or otherwise require a drill-throughprocess. Environmental- or bio-friendly materials are further desirous.

The ability to save operational time (and those saving operationalcosts) leads to considerable competition in the marketplace. Achievingany ability to save time, or ultimately cost, leads to an immediatecompetitive advantage.

Accordingly, there are needs in the art for novel systems and methodsfor isolating wellbores in a fast, viable, and economical fashion. Thereis a great need in the art for downhole plugging tools that form areliable and resilient seal against a surrounding tubular. There is alsoa need for a downhole tool made substantially of a drillable materialthat is easier and faster to drill. There is a great need in the art fora downhole tool that overcomes problems encountered in a horizontalorientation. There is a need in the art to reduce the amount of time andenergy needed to remove a workstring from a wellbore, including reducinghydraulic drag. There is a need in the art for non-metallic downholetools and components.

It is highly desirous for these downhole tools to readily and easilywithstand extreme wellbore conditions, and at the same time be cheaper,smaller, lighter, and useable in the presence of high pressuresassociated with drilling and completion operations.

SUMMARY

Embodiments of the disclosure pertain to a downhole tool suitable foruse in a wellbore. The tool may include one or more of a wedge mandrel;a fingered member disposed around the wedge mandrel; a seal elementdisposed around the wedge mandrel; a ball seat insert; a supportplatform; and a lower sleeve disposed around and engaged with wedgemandrel.

The wedge mandrel may be made of a composite filament wound material.The wedge mandrel may include: a distal end; a proximate end; an outersurface; and an inner flowbore extending through the wedge mandrel fromthe proximate end to the distal end. The wedge mandrel may have a firstouter diameter at the distal end, a second outer diameter at theproximate end. The wedge mandrel may have an angled surface (or angledlinear transition surface) therebetween. In aspects, the wedge mandrelmay have a second outer diameter larger than a first outer diameter.

The inner flowbore may include a first seat of threads at the distal endand a second set of threads at the proximate end. The ball seat insertmay be disposed in the inner flowbore and engaged with the first set ofthreads. The support platform may be disposed in the inner flowbore andengaged with the second set of threads. Either or both of the first setof threads or the second set of threads may be round threads (or have arounded thread profile).

The wedge mandrel (or its inner flowbore) may have an inner flowborediameter in the range of about 1.5 inches to about 4 inches. The ballseat insert may include a ball seat formed therein. The ball seat insertmay have a ball seat bore having an inner diameter in the range of about0.5 inches to about 1.5 inches.

In operation, and upon setting, via pressurization a ball may bepositioned in the ball seat. In aspects related to the set tool, amiddle of the ball may be laterally proximate to a middle of the sealelement.

One or more components of the downhole tool or the ball may be made of areactive material formed from an initial mixture composition comprising:a low viscosity cycloaliphatic epoxy resin with an anhydride curingagent. The reactive material may be formed via a curing process.

The downhole tool may include other components, including one or more ofa first backup ring engaged with a first side of the seal element or asecond backup ring engaged with a second side of the seal element.

The fingered member may be made from a material that includes one ormore of filament wound material, fiberglass cloth wound material, andmolded fiberglass composite. The fingered member may include: a circularbody; a plurality of fingers extending from the circular body; alongitudinal gap formed between respective fingers; and a transitionzone between the circular body and the plurality of fingers. Thetransition zone may include an inner member surface and an outer membersurface. The inner member surface may include a first inner membergroove. The outer member surface may include a first outer membergroove.

The wedge mandrel may include a plurality of lateral windows configuredfor a plurality of respective support platform dogs to movingly engagetherein. The fingered member may also have a plurality of recessedregions disposed in the circular body configured for the plurality ofrespective support platform dogs to engage therein.

One or more fingers of the fingered member may include a gripper insertdisposed therein. The gripper insert may be made of metal, such as castiron. The gripper may insert may be surface hardened. The gripper insertmay be heat treated by way of an induction process. The gripper insertmay have a gripper outer surface Rockwell hardness in the range of about40 to about 60, and a griper inner surface Rockwell hardness in therange of about 10 to about 25.

In aspects, the downhole tool may be configured as one of a frac plugand a bridge plug.

The insert may have a circular body, a first end, a second end, and ahelical winding groove formed in the circular body between the first endand the second end.

Other embodiments of the disclosure pertain to a downhole tool for usein a wellbore that may include one or more of: a wedge mandrel; afingered member disposed around the wedge mandrel; a seal elementdisposed around the mandrel; a ball seat insert disposed in the wedgemandrel; a support platform disposed in the wedge mandrel; and a lowersleeve disposed around the wedge mandrel.

The wedge mandrel may include a distal end; a proximate end; an outersurface; and an inner flowbore extending through the wedge mandrel fromthe proximate end to the distal end. The wedge mandrel may include afirst outer diameter at the distal end. The wedge mandrel may include asecond outer diameter at the proximate end. The outer surface mayinclude an axially linear surface. The outer surface may include anaxially angled surface. The outer surface may have a detent, which maybe formed between the liner surface and the angled surface. The secondouter diameter may be larger than the first outer diameter.

The ball seat insert may be engaged with an inner surface of the innerflowbore. The ball seat insert may be threadingly engaged with the innersurface. The support platform may be engaged with the inner surface. Thesupport platform may be treadingly engaged with the inner surface. Thelower sleeve may be engaged with the outer surface. The lower sleeve maybe threadingly engaged with the outer surface.

The insert may be positioned and engaged with the detent. The fingeredmember may be disposed in the assembled configuration around the axiallylinear surface.

The inner flowbore may include an inner flowbore diameter in the rangeof about 1.5 inches to about 4 inches. The ball seat insert may have aball seat formed therein. The ball seat insert may have a ball seatbore. The ball seat bore may have an inner bore diameter in the range ofabout 0.5 inches to about 1.5 inches. The support platform may have asupport platform bore having an inner support platform bore diameter inthe range of about 0.5 inches to about 1.5 inches.

In operation, upon setting of the downhole tool, via pressurization aball may be positioned in the ball seat whereby a middle of the ball maybe laterally proximate to a middle of the seal element.

The downhole tool may include other components, such as a first backupring engaged with a first side of the seal element, and/or a secondbackup ring engaged with a second side of the seal element.

The fingered member may include: a circular body; a plurality of fingersextending from the circular body; a gap or slice formed betweenrespective fingers; and a transition zone between the circular body andthe plurality of fingers. The transition zone may include an innermember surface and an outer member surface. The inner member surface mayhave a first inner member groove. The outer member surface may have afirst outer member groove.

The wedge mandrel may have one or more lateral mandrel windowsconfigured for a one or more respective support platform dogs tomovingly engage therein. The fingered member may have one or morerecessed regions disposed in the circular body configured for therespective support platform dogs to engage therein.

The fingered member, the wedge mandrel, or both, may be made ofcomposite filament wound material. One or more of the plurality offingers may have a gripper insert disposed therein.

The griper insert may be metal. The griper insert may be surfacehardened by way of an induction process resulting in a gripper outersurface Rockwell hardness in the range of about 40 to about 60, and agriper inner surface Rockwell hardness in the range of about 10 to about25.

The insert may have a circular body, a first end, a second end, and ahelical winding groove formed in the circular body between the first endand the second end.

One or more components of the downhole tool may be made of a curedreactive material formed from an initial mixture composition comprising:a low viscosity cycloaliphatic epoxy resin with an anhydride curingagent.

Yet other embodiments of the disclosure pertain to a method of operatinga downhole tool that may include one or more steps of: using aworkstring to run the downhole tool into the wellbore to a desiredposition; actuating a setting device coupled with the downhole tool inorder to set the downhole tool into at least partial engagement with asurrounding tubular; disconnecting the downhole tool from the settingdevice coupled therewith when the tensile load is sufficient to causeseparation therefrom; seating a ball in a ball seat of the downholetool; and waiting an amount of time for a reactive material to react ina sufficient manner whereby a fluid may be produced through an innerflowbore of the tool, wherein an inner flowbore diameter is in the rangeof about 2 inches to about 3 inches.

The downhole tool may include: a wedge mandrel further having: a distalend; a proximate end; an outer surface; and the inner flowbore extendingthrough the mandrel from the proximate end to the distal end. The outersurface may have an axially linear surface and an axially angledsurface. The tool may include: a fingered member disposed around themandrel; a seal element disposed around the mandrel; and a ball seatinsert disposed in the inner flowbore at the proximate end, and engagedwith the inner surface of the inner flowbore; a support platformdisposed in the inner flowbore at the distal end, and engaged with theinner surface; and a lower sleeve disposed around and engaged with theouter surface of mandrel at the distal end.

The method may include having at least one component of the downholetool or the ball made of material made from an initial mixturecomposition comprising: a cycloaliphatic epoxy resin and an anhydridecuring agent.

These and other embodiments, features and advantages will be apparent inthe following detailed description and drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

A full understanding of embodiments disclosed herein is obtained fromthe detailed description of the disclosure presented herein below, andthe accompanying drawings, which are given by way of illustration onlyand are not intended to be limitative of the present embodiments, andwherein:

FIG. 1 is a side view of a process diagram of a conventional pluggingsystem;

FIG. 2A shows an isometric view of a system having a downhole tool,according to embodiments of the disclosure;

FIG. 2B shows an isometric view of a system having a downhole tool,according to embodiments of the disclosure;

FIG. 2C shows a side longitudinal view of a downhole tool according toembodiments of the disclosure;

FIG. 2D shows a longitudinal cross-sectional view of a downhole toolaccording to embodiments of the disclosure;

FIG. 2E shows an isometric component break-out view of a downhole toolaccording to embodiments of the disclosure;

FIG. 3A shows an isometric view of a mandrel usable with a downhole toolaccording to embodiments of the disclosure;

FIG. 3B shows a longitudinal cross-sectional view of a mandrel usablewith a downhole tool according to embodiments of the disclosure;

FIG. 3C shows a longitudinal cross-sectional view of an end of a mandrelusable with a downhole tool according to embodiments of the disclosure;

FIG. 3D shows a longitudinal cross-sectional view of an end of a mandrelengaged with a sleeve according to embodiments of the disclosure;

FIG. 4A shows a longitudinal cross-sectional view of a seal elementusable with a downhole tool according to embodiments of the disclosure;

FIG. 4B shows an isometric view of a seal element usable with a downholetool according to embodiments of the disclosure;

FIG. 5A shows an isometric view of one or more slips usable with adownhole tool according to embodiments of the disclosure;

FIG. 5B shows a lateral view of one or more slips usable with a downholetool according to embodiments of the disclosure;

FIG. 5C shows a longitudinal cross-sectional view of one or more slipsusable with a downhole tool according to embodiments of the disclosure;

FIG. 5D shows an isometric view of a metal slip usable with a downholetool according to embodiments of the disclosure;

FIG. 5E shows a lateral view of a metal slip usable with a downhole toolaccording to embodiments of the disclosure;

FIG. 5F shows a longitudinal cross-sectional view of a metal slip usablewith a downhole tool according to embodiments of the disclosure;

FIG. 5G shows an isometric view of a metal slip without buoyant materialholes usable with a downhole tool according to embodiments of thedisclosure;

FIG. 6A shows an isometric view of a composite deformable member usablewith a downhole tool according to embodiments of the disclosure;

FIG. 6B shows a longitudinal cross-sectional view of a compositedeformable member usable with a downhole tool according to embodimentsof the disclosure;

FIG. 6C shows a close-up longitudinal cross-sectional view of acomposite deformable member usable with a downhole tool according toembodiments of the disclosure;

FIG. 6D shows a side longitudinal view of a composite deformable memberusable with a downhole tool according to embodiments of the disclosure;

FIG. 6E shows a longitudinal cross-sectional view of a compositedeformable member usable with a downhole tool according to embodimentsof the disclosure;

FIG. 6F shows an underside isometric view of a composite deformablemember usable with a downhole tool according to embodiments of thedisclosure;

FIG. 7A shows an isometric view of a bearing plate usable with adownhole tool according to embodiments of the disclosure;

FIG. 7B shows a longitudinal cross-sectional view of a bearing plateusable with a downhole tool according to embodiments of the disclosure;

FIG. 7C shows an isometric view of a bearing plate configured with pininserts according to embodiments of the disclosure;

FIG. 7D shows a front lateral view of a bearing plate configured withpin inserts according to embodiments of the disclosure;

FIG. 7E shows a longitudinal cross-sectional view of the bearing plateof FIG. 7D according to embodiments of the disclosure;

FIG. 7EE shows a longitudinal cross-sectional view of a bearing platewith variant pin inserts according to embodiments of the disclosure;

FIG. 8A shows an underside isometric view of a cone usable with adownhole tool according to embodiments of the disclosure;

FIG. 8B shows a longitudinal cross-sectional view of a cone usable witha downhole tool according to embodiments of the disclosure;

FIG. 9A shows an isometric view of a lower sleeve usable with a downholetool according to embodiments of the disclosure;

FIG. 9B shows a longitudinal cross-sectional view of a lower sleeveusable with a downhole tool according to embodiments of the disclosure;

FIG. 9C shows an isometric view of a lower sleeve configured withstabilizer pin inserts according to embodiments of the disclosure;

FIG. 9D shows a lateral view of the lower sleeve of FIG. 9C according toembodiments of the disclosure;

FIG. 9E shows a longitudinal cross-sectional view of the lower sleeve ofFIG. 9C according to embodiments of the disclosure;

FIG. 10A shows a longitudinal cross-sectional view of a mandrelconfigured with a relief point according to embodiments of thedisclosure;

FIG. 10B shows a longitudinal side view of the mandrel of FIG. 10Aaccording to embodiments of the disclosure;

FIG. 11A shows a side view of a channeled sleeve according toembodiments of the disclosure;

FIG. 11B shows an isometric view of the channeled sleeve of FIG. 11Aaccording to embodiments of the disclosure;

FIG. 11C shows a lateral view of the channeled sleeve of FIG. 11Aaccording to embodiments of the disclosure;

FIG. 12A shows an isometric view of a metal slip according toembodiments of the disclosure;

FIG. 12B shows a lateral side view of a metal slip according toembodiments of the disclosure;

FIG. 12C shows a lateral view of a metal slip engaged with a sleeveaccording to embodiments of the disclosure;

FIG. 12D shows a close up lateral view of a stabilizer pin in a variedengagement position with an asymmetrical mating hole according toembodiments of the disclosure;

FIG. 12E shows a close up lateral view of a stabilizer pin in a variedengagement position with an asymmetrical mating hole according toembodiments of the disclosure;

FIG. 12F shows a close up lateral view of a stabilizer pin in a variedengagement positions with an asymmetrical mating hole according toembodiments of the disclosure;

FIG. 12G shows an isometric view of a metal slip configured with fourmating holes according to embodiments of the disclosure;

FIG. 13A shows an isometric view of a metal slip according toembodiments of the disclosure;

FIG. 13B shows a longitudinal cross-section view of the metal slip ofFIG. 13A according to embodiments of the disclosure;

FIG. 13C shows a longitudinal cross-section view of the metal slip ofFIG. 13A according to embodiments of the disclosure;

FIG. 13D shows a lateral view of the metal slip of FIG. 13A according toembodiments of the disclosure;

FIG. 14A shows an isometric view of a downhole tool with a wedge mandrelaccording to embodiments of the disclosure;

FIG. 14B shows a longitudinal side view of the downhole tool of FIG. 14Aaccording to embodiments of the disclosure;

FIG. 14C shows a component breakout view of the downhole tool of FIG.14A according to embodiments of the disclosure;

FIG. 15A shows an isometric view of a wedge mandrel according toembodiments of the disclosure;

FIG. 15B shows a longitudinal side cross-sectional view of the wedgemandrel of FIG. 15A according to embodiments of the disclosure;

FIG. 16A shows an isometric view of a ball seat insert according toembodiments of the disclosure;

FIG. 16B shows a longitudinal side cross-sectional view of the ball seatinsert of FIG. 16A according to embodiments of the disclosure;

FIG. 17A shows an isometric view of a fingered member according toembodiments of the disclosure;

FIG. 17B shows a longitudinal side cross-sectional view of the fingeredmember of FIG. 17A according to embodiments of the disclosure;

FIG. 17C shows a downward view of a gripper insert having serrated teethaccording to embodiments of the disclosure;

FIG. 17D shows a side view of a gripper insert having serrated teeth oneach side according to embodiments of the disclosure;

FIG. 18A shows a side expanded view of an insert according toembodiments of the disclosure;

FIG. 18B shows a side collapsed view of the insert of FIG. 18A accordingto embodiments of the disclosure;

FIG. 18C shows an isometric view of an insert according to embodimentsof the disclosure;

FIG. 19A shows an engaged side view of a seal element between a firstand second backup ring according to embodiments of the disclosure;

FIG. 19B shows an exploded side view of a seal element between a firstand second backup ring according to embodiments of the disclosure;

FIG. 20A shows an isometric view of a support platform according toembodiments of the disclosure;

FIG. 20B shows a lateral side view of the support platform of FIG. 20Aaccording to embodiments of the disclosure;

FIG. 21A shows an isometric view of a lower sleeve according toembodiments of the disclosure;

FIG. 21B shows a longitudinal side view of the lower sleeve of FIG. 21Aaccording to embodiments of the disclosure;

FIG. 22A shows a longitudinal cross-sectional view of a system havingdownhole tool run to a location within a tubular according toembodiments of the disclosure;

FIG. 22B shows a longitudinal side cross-sectional view of the downholetool of FIG. 22A moved to a set position according to embodiments of thedisclosure;

FIG. 22C shows a longitudinal side cross-sectional view of the downholetool of FIG. 22A set in a tubular and separated from a workstringaccording to embodiments of the disclosure;

FIG. 22D shows a longitudinal side cross-sectional view of the downholetool of FIG. 22A having various internal components removed therefromaccording to embodiments of the disclosure; and

FIG. 22E shows a close-up side cross-sectional view of an alternativeadapter connection to a downhole tool according to embodiments of thedisclosure.

DETAILED DESCRIPTION

Herein disclosed are novel apparatuses, systems, and methods thatpertain to and are usable for a downhole tool for wellbore operations,details of which are described herein.

Embodiments of the present disclosure are described in detail withreference to the accompanying Figures. In the following discussion andin the claims, the terms “including” and “comprising” are used in anopen-ended fashion, such as to mean, for example, “including, but notlimited to . . . ”. While the disclosure may be described with referenceto relevant apparatuses, systems, and methods, it should be understoodthat the disclosure is not limited to the specific embodiments shown ordescribed. Rather, one skilled in the art will appreciate that a varietyof configurations may be implemented in accordance with embodimentsherein.

Although not necessary, like elements in the various figures may bedenoted by like reference numerals for consistency and ease ofunderstanding. Numerous specific details are set forth in order toprovide a more thorough understanding of the disclosure; however, itwill be apparent to one of ordinary skill in the art that theembodiments disclosed herein may be practiced without these specificdetails. In other instances, well-known features have not been describedin detail to avoid unnecessarily complicating the description.Directional terms, such as “above,” “below,” “upper,” “lower,” “front,”“back,” etc., are used for convenience and to refer to general directionand/or orientation, and are only intended for illustrative purposesonly, and not to limit the disclosure.

Connection(s), couplings, or other forms of contact between parts,components, and so forth may include conventional items, such aslubricant, additional sealing materials, such as a gasket betweenflanges, PTFE between threads, and the like. The make and manufacture ofany particular component, subcomponent, etc., may be as would beapparent to one of skill in the art, such as molding, forming, pressextrusion, machining, or additive manufacturing. Embodiments of thedisclosure provide for one or more components to be new, used, and/orretrofitted.

Numerical ranges in this disclosure may be approximate, and thus mayinclude values outside of the range unless otherwise indicated.Numerical ranges include all values from and including the expressedlower and the upper values, in increments of smaller units. As anexample, if a compositional, physical or other property, such as, forexample, molecular weight, viscosity, melt index, etc., is from 100 to1,000, it is intended that all individual values, such as 100, 101, 102,etc., and sub ranges, such as 100 to 144, 155 to 170, 197 to 200, etc.,are expressly enumerated. It is intended that decimals or fractionsthereof be included. For ranges containing values which are less thanone or containing fractional numbers greater than one (e.g., 1.1, 1.5,etc.), smaller units may be considered to be 0.0001, 0.001, 0.01, 0.1,etc. as appropriate. These are only examples of what is specificallyintended, and all possible combinations of numerical values between thelowest value and the highest value enumerated, are to be considered tobe expressly stated in this disclosure.

Terms

Composition of matter: as used herein may refer to one or moreingredients or constituents that make up a material (or material ofconstruction). For example, a material may have a composition of matter.Similarly, a device may be made of a material having a composition ofmatter. The composition of matter may be derived from an initialcomposition.

Reactive Material: as used herein may refer a material with acomposition of matter having properties and/or characteristics thatresult in the material responding to a change over time and/or undercertain conditions. Reactive material may encompass degradable,dissolvable, disassociatable, and so on.

Degradable Material: as used herein may refer to a composition of matterhaving properties and/or characteristics that, while subject to changeover time and/or under certain conditions, lead to a change in theintegrity of the material. As one example, the material may initially behard, rigid, and strong at ambient or surface conditions, but over time(such as within about 12-36 hours) and under certain conditions (such aswellbore conditions), the material softens.

Dissolvable Material: analogous to degradable material; as used hereinmay refer to a composition of matter having properties and/orcharacteristics that, while subject to change over time and/or undercertain conditions, lead to a change in the integrity of the material,including to the point of degrading, or partial or complete dissolution.As one example, the material may initially be hard, rigid, and strong atambient or surface conditions, but over time (such as within about 12-36hours) and under certain conditions (such as wellbore conditions), thematerial softens. As another example, the material may initially behard, rigid, and strong at ambient or surface conditions, but over time(such as within about 12-36 hours) and under certain conditions (such aswellbore conditions), the material dissolves at least partially, and maydissolve completely. The material may dissolve via one or moremechanisms, such as oxidation, reduction, deterioration, go intosolution, or otherwise lose sufficient mass and structural integrity.

Breakable Material: as used herein may refer to a composition of matterhaving properties and/or characteristics that, while subject to changeover time and/or under certain conditions, lead to brittleness. As oneexample, the material may be hard, rigid, and strong at ambient orsurface conditions, but over time and under certain conditions, becomesbrittle. The breakable material may experience breakage into multiplepieces, but not necessarily dissolution.

Disassociatable Material: as used herein may refer to a composition ofmatter having properties and/or characteristics that, while subject tochange over time and/or under certain conditions, lead to a change inthe integrity of the material, including to the point of changing from asolid structure to a powdered material. As one example, the material mayinitially be hard, rigid, and strong at ambient or surface conditions,but over time (such as within about 12-36 hours) and under certainconditions (such as wellbore conditions), the material changes(disassociates) to a powder.

For some embodiments, a material of construction may include acomposition of matter designed or otherwise having the inherentcharacteristic to react or change integrity or other physical attributewhen exposed to certain wellbore conditions, such as a change in time,temperature, water, heat, pressure, solution, combinations thereof, etc.Heat may be present due to the temperature increase attributed to thenatural temperature gradient of the earth, and water may already bepresent in existing wellbore fluids. The change in integrity may occurin a predetermined time period, which may vary from several minutes toseveral weeks. In aspects, the time period may be about 12 to about 36hours.

In some embodiments, the material may degrade to the point of ‘mush’ ordisassociate to a powder, while in other embodiments, the material maydissolve or otherwise disintegrate and be carried away by fluid flowingin the wellbore. The temperature of the downhole fluid may affect therate change in integrity. The material need not form a solution when itdissolves in the aqueous phase. For example, the material may dissolve,break, or otherwise disassociate into sufficiently small particles(i.e., a colloid), that may be removed by the fluid as it circulates inthe well. In embodiments, the material may become degradable, but notdissolvable. In other embodiments, the material may become degradable,and subsequently dissolvable. In still other embodiments, the materialmay become breakable (or brittle), but not dissolvable. In yet otherembodiments, the material may become breakable, and subsequentlydissolvable. In still yet other embodiments, the material maydisassociate.

Referring now to FIGS. 2A and 2B together, isometric views of a system200 having a downhole tool 202 illustrative of embodiments disclosedherein, are shown. FIG. 2B depicts a wellbore 206 formed in asubterranean formation 210 with a tubular 208 disposed therein. In anembodiment, the tubular 208 may be casing (e.g., casing, hung casing,casing string, etc.) (which may be cemented). A workstring 212 (whichmay include a part 217 of a setting tool coupled with adapter 252) maybe used to position or run the downhole tool 202 into and through thewellbore 206 to a desired location.

In accordance with embodiments of the disclosure, the tool 202 may beconfigured as a plugging tool, which may be set within the tubular 208in such a manner that the tool 202 forms a fluid-tight seal against theinner surface 207 of the tubular 208. In an embodiment, the downholetool 202 may be configured as a bridge plug, whereby flow from onesection of the wellbore 213 to another (e.g., above and below the tool202) is controlled. In other embodiments, the downhole tool 202 may beconfigured as a frac plug, where flow into one section 213 of thewellbore 206 may be blocked and otherwise diverted into the surroundingformation or reservoir 210.

In yet other embodiments, the downhole tool 202 may also be configuredas a ball drop tool. In this aspect, a ball may be dropped into thewellbore 206 and flowed into the tool 202 and come to rest in acorresponding ball seat at the end of the mandrel 214. The seating ofthe ball may provide a seal within the tool 202 resulting in a pluggedcondition, whereby a pressure differential across the tool 202 mayresult. The ball seat may include a radius or curvature.

In other embodiments, the downhole tool 202 may be a ball check plug,whereby the tool 202 is configured with a ball already in place when thetool 202 runs into the wellbore. The tool 202 may then act as a checkvalve, and provide one-way flow capability. Fluid may be directed fromthe wellbore 206 to the formation with any of these configurations.

Once the tool 202 reaches the set position within the tubular, thesetting mechanism or workstring 212 may be detached from the tool 202 byvarious methods, resulting in the tool 202 left in the surroundingtubular and one or more sections of the wellbore isolated. In anembodiment, once the tool 202 is set, tension may be applied to theadapter 252 until the threaded connection between the adapter 252 andthe mandrel 214 is broken. For example, the mating threads on theadapter 252 and the mandrel 214 (256 and 216, respectively as shown inFIG. 2D) may be designed to shear, and thus may be pulled and shearedaccordingly in a manner known in the art. The amount of load applied tothe adapter 252 may be in the range of about, for example, 20,000 to40,000 pounds force. In other applications, the load may be in the rangeof less than about 10,000 pounds force.

Accordingly, the adapter 252 may separate or detach from the mandrel214, resulting in the workstring 212 being able to separate from thetool 202, which may be at a predetermined moment. The loads providedherein are non-limiting and are merely exemplary. The setting force maybe determined by specifically designing the interacting surfaces of thetool and the respective tool surface angles. The tool 202 may also beconfigured with a predetermined failure point (not shown) configured tofail or break. For example, the failure point may break at apredetermined axial force greater than the force required to set thetool but less than the force required to part the body of the tool.

Operation of the downhole tool 202 may allow for fast run in of the tool202 to isolate one or more sections of the wellbore 206, as well asquick and simple drill-through to destroy or remove the tool 202.Drill-through of the tool 202 may be facilitated by components andsub-components of tool 202 made of drillable material that is lessdamaging to a drill bit than those found in conventional plugs. In anembodiment, the downhole tool 202 and/or its components may be adrillable tool made from drillable composite material(s), such as glassfiber/epoxy, carbon fiber/epoxy, glass fiber/PEEK, carbon fiber/PEEK,etc. Other resins may include phenolic, polyamide, etc. All matingsurfaces of the downhole tool 202 may be configured with an angle, suchthat corresponding components may be placed under compression instead ofshear.

The downhole tool 202 may have one or more components made ofnon-composite material, such as a metal or metal alloys. The downholetool 2102 may have one or more components made of a reactive material(e.g., dissolvable, degradable, etc.).

In embodiments, one or more components may be made of a metallicmaterial, such as an aluminum-based or magnesium-based material. Themetallic material may be reactive, such as dissolvable, which is to sayunder certain conditions the respective component(s) may begin todissolve, and thus alleviating the need for drill thru. In embodiments,the components of the tool 202 may be made of dissolvable aluminum-,magnesium-, or aluminum-magnesium-based (or alloy, complex, etc.)material, such as that provided by Nanjing Highsur Composite MaterialsTechnology Co. LTD.

One or more components of tool 202 may be made of non-dissolvablematerials (e.g., materials suitable for and are known to withstanddownhole environments [including extreme pressure, temperature, fluidproperties, etc.] for an extended period of time (predetermined orotherwise) as may be desired).

Just the same, one or more components of a tool of embodiments disclosedherein may be made of reactive materials (e.g., materials suitable forand are known to dissolve, degrade, etc. in downhole environments[including extreme pressure, temperature, fluid properties, etc.] aftera brief or limited period of time (predetermined or otherwise) as may bedesired). In an embodiment, a component made of a reactive material maybegin to react within about 3 to about 48 hours after setting of thedownhole tool 202.

The downhole tool 202 (and other tool embodiments disclosed herein)and/or one or more of its components may be 3D printed as would beapparent to one of skill in the art, such as via one or more methods orprocesses described in U.S. Pat. Nos. 6,353,771; 5,204,055; 7,087,109;7,141,207; and 5,147, 587. See also information available at thewebsites of Z Corporation (www.zcorp.com); Prometal (www.prometal.com);EOS GmbH (www.eos.info); and 3D Systems, Inc. (www.3dsystems.com); andStratasys, Inc. (www.stratasys.com and www.dimensionprinting.com)(applicable to all embodiments).

Referring now to FIGS. 2C-2E together, a longitudinal view, alongitudinal cross-sectional view, and an isometric component break-outview, respectively, of downhole tool 202 useable with system (200, FIG.2A) and illustrative of embodiments disclosed herein, are shown. Thedownhole tool 202 may include a mandrel 214 that extends through thetool (or tool body) 202. The mandrel 214 may be a solid body. In otheraspects, the mandrel 214 may include a flowpath or bore 250 formedtherein (e.g., an axial bore). The bore 250 may extend partially or fora short distance through the mandrel 214, as shown in FIG. 2E.Alternatively, the bore 250 may extend through the entire mandrel 214,with an opening at its proximate end 248 and oppositely at its distalend 246 (near downhole end of the tool 202), as illustrated by FIG. 2D.

The presence of the bore 250 or other flowpath through the mandrel 214may indirectly be dictated by operating conditions. That is, in mostinstances the tool 202 may be large enough in diameter (e.g., 4¾ inches)that the bore 250 may be correspondingly large enough (e.g., 1¼ inches)so that debris and junk can pass or flow through the bore 250 withoutplugging concerns. However, with the use of a smaller diameter tool 202,the size of the bore 250 may need to be correspondingly smaller, whichmay result in the tool 202 being prone to plugging. Accordingly, themandrel may be made solid to alleviate the potential of plugging withinthe tool 202.

With the presence of the bore 250, the mandrel 214 may have an innerbore surface 247, which may include one or more threaded surfaces formedthereon. As such, there may be a first set of threads 216 configured forcoupling the mandrel 214 with corresponding threads 256 of a settingadapter 252.

The coupling of the threads, which may be shear threads, may facilitatedetachable connection of the tool 202 and the setting adapter 252 and/orworkstring (212, FIG. 2B) at the threads. It is within the scope of thedisclosure that the tool 202 may also have one or more predeterminedfailure points (not shown) configured to fail or break separately fromany threaded connection. The failure point may fail or shear at apredetermined axial force greater than the force required to set thetool 202. In an embodiment, the mandrel 214 may be configured with afailure point.

Referring briefly to FIGS. 10A and 10B, a longitudinal cross-sectionalview and a longitudinal side view, respectively, of a mandrel configuredwith a relief point, are shown. In FIGS. 10A and 10B together, anembodiment of a mandrel 2114 configured with a relief point (or area,region, etc.) 2161. The relief point 2161 may be formed by machining outor otherwise forming a groove 2164 in mandrel end 2148. The groove 2164may be formed circumferentially in the mandrel 2114. The mandrel 2114may be useable with any downhole tool embodiment disclosed herein, suchas tool 202, 302, etc.

This type of configuration may allow, for example, where, in someapplications, it may be desirable, to rip off or shear mandrel head 2165instead of shearing threads 2116. In this respect, failing composite (orglass fibers) in tension may be potentially more accurate then shearingthreads.

Referring again to FIGS. 2C-2E together, the adapter 252 may include astud 253 configured with the threads 256 thereon. In an embodiment, thestud 253 has external (male) threads 256 and the mandrel 214 hasinternal (female) threads; however, type or configuration of threads isnot meant to be limited, and could be, for example, a vice versafemale-male connection, respectively.

The downhole tool 202 may be run into wellbore (206, FIG. 2A) to adesired depth or position by way of the workstring (212, FIG. 2A) thatmay be configured with the setting device or mechanism. The workstring212 and setting sleeve 254 may be part of the plugging tool system 200utilized to run the downhole tool 202 into the wellbore, and activatethe tool 202 to move from an unset to set position. The set position mayinclude seal element 222 and/or slips 234, 242 engaged with the tubular(208, FIG. 2B). In an embodiment, the setting sleeve 254 (that may beconfigured as part of the setting mechanism or workstring) may beutilized to force or urge compression of the seal element 222, as wellas swelling of the seal element 222 into sealing engagement with thesurrounding tubular.

Referring briefly to FIGS. 11A, 11B, and 11C, a pre-setting downholeview, a downhole view, a longitudinal side body view, an isometric view,and a lateral cross-sectional view, respectively, of a setting sleevehaving a reduced hydraulic diameter illustrative of embodimentsdisclosed herein, are shown. FIGS. 11A-11C illustrate a sleeve 1954configured with one or more grooves or channels 1955 configured to allowwellbore fluid to readily pass therein, therethrough, thereby, etc.,consequently resulting in reduction of the hydraulic resistance (e.g.,drag) against the workstring 1905 as it is removed from the wellbore1908. Or put another way, that hydraulic pressure above the settingsleeve 1954 can be ‘relieved’ or bypassed below the sleeve 1954.Channels 1955 may also provide pressure relief during perforationbecause at least some of the pressure (or shock) wave can be alleviated.Prior to setting and removal, the sleeve 1954 may be in operableengagement with the downhole tool 1902. In an embodiment, the downholetool 1902 may be a frac plug.

Because of the large pressures incurred, in using a sleeve 1954 withreduced hydraulic cross-section, it is important to maintain integrity.That is, any sleeve of embodiments disclosed herein must still be robustand inherent in strength to withstand shock pressure, setting forces,etc., and avoid component failure or collapse.

FIGS. 11A-11C together show setting sleeve 1954 may have a first end1957 and a second end 1958. One or more channels 1955 may extend orotherwise be disposed a length L along the outer surface 1960 of thesleeve 1954. The channel(s) may be parallel or substantially parallel tosleeve axis 1961. One or more channels 1955 may be part of a channelgroup 1962. There may be multiple channel groups 1962 in the sleeve1955. As shown in the Figures here, there may be three (3) channelgroups 1962. The groups 1962 of channels 1955 may be arranged in anequilateral pattern around the circumference of the sleeve 1954.Indicator ring 1956 illustrates how the outer diameter (or hydraulicdiameter) is effectively reduced by the presence of channel(s) 1955. Orput another way, that the sleeve 1954 may have an effective outersurface area greater than an actual outer surface area (e.g., becausethe actual outermost surface area of the sleeve in the circumferentialsense is “void” of area).

Although FIGS. 11A-11C depict one example, embodiments herein pertainingto the sleeve 1954 are not meant to be limited thereby. One of skill inthe art would appreciate there may be other configurations of channel(s)suitable to reduce the hydraulic diameter of the sleeve 1954 (and/orprovide fluid bypass capability), but yet provide the sleeve 1954 withadequate integrity suitable for setting, downhole conditions, and soforth.

There may be a channel(s) arranged in a non-axial or non-linear manner,for example, as spiral-wound, helical etc. It is worth noting thatalthough embodiments of the sleeve channel may extend from one end ofthe sleeve 1957 to approximately the other end of the sleeve 1958, thisneed not be the case. Thus, the length of the channel L may be less thanthe length LS of the sleeve 1955. In addition, the channel need not becontinuous, such that there may be discontinuous channels.

Other variants of sleeve 1954 having a certain channel groove pattern orcross-sectional shape are possible, including one or more channelshaving a “v-notch”, as well as an ‘offset’ V-notch, an opposite offsetV-notch, a “square” notch, a rounded notch, and combinations thereof(not shown). Moreover, although the groups of channels may be disposedor arranged equidistantly apart, the groups may just as well have anunequal or random placement or distribution. Although the channelpattern or cross-sectional shape may be consistent and continuous, thescope of the disclosure is not limited to such a pattern. Thus, thepattern or cross-sectional shape may vary or have randomdiscontinuities.

Yet other embodiments may include one or more channels disposed withinthe sleeve instead of on the outer surface. For example, the sleeve 1954may include a channel formed within the body (or wall thickness) of thesleeve, thus forming an inner passageway for fluid to flow therethrough.

Returning again to FIGS. 2C-2E together, the setting device(s) andcomponents of the downhole tool 202 may be coupled with, and axiallyand/or longitudinally movable along mandrel 214. When the settingsequence begins, the mandrel 214 may be pulled into tension while thesetting sleeve 254 remains stationary. The lower sleeve 260 may bepulled as well because of its attachment to the mandrel 214 by virtue ofthe coupling of threads 218 and threads 262. As shown in the embodimentof FIGS. 2C and 2D, the lower sleeve 260 and the mandrel 214 may havematched or aligned holes 281A and 281B, respectively, whereby one ormore anchor pins 211 or the like may be disposed or securely positionedtherein. In embodiments, brass set screws may be used. Pins (or screws,etc.) 211 may prevent shearing or spin-off during drilling or run-in.

As the lower sleeve 260 is pulled in the direction of Arrow A, thecomponents disposed about mandrel 214 between the lower sleeve 260 andthe setting sleeve 254 may begin to compress against one another. Thisforce and resultant movement causes compression and expansion of sealelement 222. The lower sleeve 260 may also have an angled sleeve end 263in engagement with the slip 234, and as the lower sleeve 260 is pulledfurther in the direction of Arrow A, the end 263 compresses against theslip 234. As a result, slip(s) 234 may move along a tapered or angledsurface 228 of a composite member 220, and eventually radially outwardinto engagement with the surrounding tubular (208, FIG. 2B).

Serrated outer surfaces or teeth 298 of the slip(s) 234 may beconfigured such that the surfaces 298 prevent the slip 234 (or tool)from moving (e.g., axially or longitudinally) within the surroundingtubular, whereas otherwise the tool 202 may inadvertently release ormove from its position. Although slip 234 is illustrated with teeth 298,it is within the scope of the disclosure that slip 234 may be configuredwith other gripping features, such as buttons or inserts.

Initially, the seal element 222 may swell into contact with the tubular,followed by further tension in the tool 202 that may result in the sealelement 222 and composite member 220 being compressed together, suchthat surface 289 acts on the interior surface 288. The ability to“flower”, unwind, and/or expand may allow the composite member 220 toextend completely into engagement with the inner surface of thesurrounding tubular.

The composite member 220 may provide other synergistic benefits beyondthat of creating enhanced sealing. Without the ability to ‘flower’, thehydraulic cross-section is essentially the back of the tool. However,with a ‘flower’ effect the hydraulic cross-section becomes dynamic, andis increased. This allows for faster run-in and reduced fluidrequirements compared to conventional operations. This is even ofgreater significance in horizontal applications. In various testing,tools configured with a composite member 220 required about 40 lessminutes of run-in compared to conventional tools. When downholeoperations run about $30,000-$40,000 per hour, a savings of 40 minutesis of significance.

Additional tension or load may be applied to the tool 202 that resultsin movement of cone 236, which may be disposed around the mandrel 214 ina manner with at least one surface 237 angled (or sloped, tapered, etc.)inwardly of second slip 242. The second slip 242 may reside adjacent orproximate to collar or cone 236. As such, the seal element 222 forcesthe cone 236 against the slip 242, moving the slip 242 radiallyoutwardly into contact or gripping engagement with the tubular.Accordingly, the one or more slips 234, 242 may be urged radiallyoutward and into engagement with the tubular (208, FIG. 2B). In anembodiment, cone 236 may be slidingly engaged and disposed around themandrel 214. As shown, the first slip 234 may be at or near distal end246, and the second slip 242 may be disposed around the mandrel 214 ator near the proximate end 248. It is within the scope of the disclosurethat the position of the slips 234 and 242 may be interchanged.Moreover, slip 234 may be interchanged with a slip comparable to slip242, and vice versa.

Because the sleeve 254 is held rigidly in place, the sleeve 254 mayengage against a bearing plate 283 that may result in the transfer loadthrough the rest of the tool 202. The setting sleeve 254 may have asleeve end 255 that abuts against the bearing plate end 284. As tensionincreases through the tool 202, an end of the cone 236, such as secondend 240, compresses against slip 242, which may be held in place by thebearing plate 283. As a result of cone 236 having freedom of movementand its conical surface 237, the cone 236 may move to the undersidebeneath the slip 242, forcing the slip 242 outward and into engagementwith the surrounding tubular (208, FIG. 2B).

The second slip 242 may include one or more, gripping elements, such asbuttons or inserts 278, which may be configured to provide additionalgrip with the tubular. The inserts 278 may have an edge or corner 279suitable to provide additional bite into the tubular surface. In anembodiment, the inserts 278 may be mild steel, such as 1018 heat treatedsteel. The use of mild steel may result in reduced or eliminated casingdamage from slip engagement and reduced drill string and equipmentdamage from abrasion.

In an embodiment, slip 242 may be a one-piece slip, whereby the slip 242has at least partial connectivity across its entire circumference.Meaning, while the slip 242 itself may have one or more grooves (ornotches, undulations, etc.) 244 configured therein, the slip 242 itselfhas no initial circumferential separation point. In an embodiment, thegrooves 244 may be equidistantly spaced or disposed in the second slip242. In other embodiments, the grooves 244 may have an alternatinglyarranged configuration. That is, one groove 244A may be proximate toslip end 241, the next groove 244B may be proximate to an opposite slipend 243, and so forth.

The tool 202 may be configured with ball plug check valve assembly thatincludes a ball seat 286. The assembly may be removable or integrallyformed therein. In an embodiment, the bore 250 of the mandrel 214 may beconfigured with the ball seat 286 formed or removably disposed therein.In some embodiments, the ball seat 286 may be integrally formed withinthe bore 250 of the mandrel 214. In other embodiments, the ball seat 286may be separately or optionally installed within the mandrel 214, as maybe desired.

The ball seat 286 may be configured in a manner so that a ball 285 seatsor rests therein, whereby the flowpath through the mandrel 214 may beclosed off (e.g., flow through the bore 250 is restricted or controlledby the presence of the ball 285). For example, fluid flow from onedirection may urge and hold the ball 285 against the seat 286, whereasfluid flow from the opposite direction may urge the ball 285 off or awayfrom the seat 286. As such, the ball 285 and the check valve assemblymay be used to prevent or otherwise control fluid flow through the tool202. The ball 285 may be conventionally made of a composite material,phenolic resin, etc., whereby the ball 285 may be capable of holdingmaximum pressures experienced during downhole operations (e.g.,fracing). By utilization of retainer pin 287, the ball 285 and ball seat286 may be configured as a retained ball plug. As such, the ball 285 maybe adapted to serve as a check valve by sealing pressure from onedirection, but allowing fluids to pass in the opposite direction.

The tool 202 may be configured as a drop ball plug, such that a dropball may be flowed to a drop ball seat 259. The drop ball may be muchlarger diameter than the ball of the ball check. In an embodiment, end248 may be configured with a drop ball seat surface 259 such that thedrop ball may come to rest and seat at in the seat proximate end 248. Asapplicable, the drop ball (not shown here) may be lowered into thewellbore (206, FIG. 2A) and flowed toward the drop ball seat 259 formedwithin the tool 202. The ball seat may be formed with a radius 259A(i.e., circumferential rounded edge or surface).

In other aspects, the tool 202 may be configured as a bridge plug, whichonce set in the wellbore, may prevent or allow flow in either direction(e.g., upwardly/downwardly, etc.) through tool 202. Accordingly, itshould be apparent to one of skill in the art that the tool 202 of thepresent disclosure may be configurable as a frac plug, a drop ball plug,bridge plug, etc. simply by utilizing one of a plurality of adapters orother optional components. In any configuration, once the tool 202 isproperly set, fluid pressure may be increased in the wellbore, such thatfurther downhole operations, such as fracture in a target zone, maycommence.

The tool 202 may include an anti-rotation assembly that includes ananti-rotation device or mechanism 282, which may be a spring, amechanically spring-energized composite tubular member, and so forth.The device 282 may be configured and usable for the prevention ofundesired or inadvertent movement or unwinding of the tool 202components. As shown, the device 282 may reside in cavity 294 of thesleeve (or housing) 254. During assembly the device 282 may be held inplace with the use of a lock ring 296. In other aspects, pins may beused to hold the device 282 in place.

FIG. 2D shows the lock ring 296 may be disposed around a part 217 of asetting tool coupled with the workstring 212. The lock ring 296 may besecurely held in place with screws inserted through the sleeve 254. Thelock ring 296 may include a guide hole or groove 295, whereby an end282A of the device 282 may slidingly engage therewith. Protrusions ordogs 295A may be configured such that during assembly, the mandrel 214and respective tool components may ratchet and rotate in one directionagainst the device 282; however, the engagement of the protrusions 295Awith device end 282B may prevent back-up or loosening in the oppositedirection.

The anti-rotation mechanism may provide additional safety for the tooland operators in the sense it may help prevent inoperability of tool insituations where the tool is inadvertently used in the wrongapplication. For example, if the tool is used in the wrong temperatureapplication, components of the tool may be prone to melt, whereby thedevice 282 and lock ring 296 may aid in keeping the rest of the tooltogether. As such, the device 282 may prevent tool components fromloosening and/or unscrewing, as well as prevent tool 202 unscrewing orfalling off the workstring 212.

Drill-through of the tool 202 may be facilitated by the fact that themandrel 214, the slips 234, 242, the cone(s) 236, the composite member220, etc. may be made of drillable material that is less damaging to adrill bit than those found in conventional plugs. The drill bit willcontinue to move through the tool 202 until the downhole slip 234 and/or242 are drilled sufficiently that such slip loses its engagement withthe well bore. When that occurs, the remainder of the tools, whichgenerally would include lower sleeve 260 and any portion of mandrel 214within the lower sleeve 260 falls into the well. If additional tool(s)202 exist in the well bore beneath the tool 202 that is being drilledthrough, then the falling away portion will rest atop the tool 202located further in the well bore and will be drilled through inconnection with the drill through operations related to the tool 202located further in the well bore. Accordingly, the tool 202 may besufficiently removed, which may result in opening the tubular 208.

Referring now to FIGS. 3A, 3B, 3C and 3D together, an isometric view anda longitudinal cross-sectional view of a mandrel usable with a downholetool, a longitudinal cross-sectional view of an end of a mandrel, and alongitudinal cross-sectional view of an end of a mandrel engaged with asleeve, in accordance with embodiments disclosed herein, are shown.Components of the downhole tool may be arranged and disposed about themandrel 314, as described and understood to one of skill in the art, andmay be comparable to other embodiments disclosed herein (e.g., seedownhole tool 202 with mandrel 214).

The mandrel 314, which may be made from filament wound drillablematerial, may have a distal end 346 and a proximate end 348. Thefilament wound material may be made of various angles as desired toincrease strength of the mandrel 314 in axial and radial directions. Thepresence of the mandrel 314 may provide the tool with the ability tohold pressure and linear forces during setting or plugging operations.

The mandrel 314 may be sufficient in length, such that the mandrel mayextend through a length of tool (or tool body) (202, FIG. 2B). Themandrel 314 may be a solid body. In other aspects, the mandrel 314 mayinclude a flowpath or bore 350 formed therethrough (e.g., an axialbore). There may be a flowpath or bore 350, for example an axial bore,that extends through the entire mandrel 314, with openings at both theproximate end 348 and oppositely at its distal end 346. Accordingly, themandrel 314 may have an inner bore surface 347, which may include one ormore threaded surfaces formed thereon.

The ends 346, 348 of the mandrel 314 may include internal or external(or both) threaded portions. As shown in FIG. 3C, the mandrel 314 mayhave internal threads 316 within the bore 350 configured to receive amechanical or wireline setting tool, adapter, etc. (not shown here). Forexample, there may be a first set of threads 316 configured for couplingthe mandrel 314 with corresponding threads of another component (e.g.,adapter 252, FIG. 2B). In an embodiment, the first set of threads 316are shear threads. In an embodiment, application of a load to themandrel 314 may be sufficient enough to shear the first set of threads316. Although not necessary, the use of shear threads may eliminate theneed for a separate shear ring or pin, and may provide for shearing themandrel 314 from the workstring.

The proximate end 348 may include an outer taper 348A. The outer taper348A may help prevent the tool from getting stuck or binding. Forexample, during setting the use of a smaller tool may result in the toolbinding on the setting sleeve, whereby the use of the outer taper 348will allow the tool to slide off easier from the setting sleeve. In anembodiment, the outer taper 348A may be formed at an angle φ of about 5degrees with respect to the axis 358. The length of the taper 348A maybe about 0.5 inches to about 0.75 inches

There may be a neck or transition portion 349, such that the mandrel mayhave variation with its outer diameter. In an embodiment, the mandrel314 may have a first outer diameter D1 that is greater than a secondouter diameter D2. Conventional mandrel components are configured withshoulders (i.e., a surface angle of about 90 degrees) that result incomponents prone to direct shearing and failure. In contrast,embodiments of the disclosure may include the transition portion 349configured with an angled transition surface 349A. A transition surfaceangle b may be about 25 degrees with respect to the tool (or toolcomponent axis) 358.

The transition portion 349 may withstand radial forces upon compressionof the tool components, thus sharing the load. That is, upon compressionthe bearing plate 383 and mandrel 314, the forces are not oriented injust a shear direction. The ability to share load(s) among componentsmeans the components do not have to be as large, resulting in an overallsmaller tool size.

In addition to the first set of threads 316, the mandrel 314 may have asecond set of threads 318. In one embodiment, the second set of threads318 may be rounded threads disposed along an external mandrel surface345 at the distal end 346. The use of rounded threads may increase theshear strength of the threaded connection.

FIG. 3D illustrates an embodiment of component connectivity at thedistal end 346 of the mandrel 314. As shown, the mandrel 314 may becoupled with a sleeve 360 having corresponding threads 362 configured tomate with the second set of threads 318. In this manner, setting of thetool may result in distribution of load forces along the second set ofthreads 318 at an angle a away from axis 358. There may be one or moreballs 364 disposed between the sleeve 360 and slip 334. The balls 364may help promote even breakage of the slip 334.

Accordingly, the use of round threads may allow a non-axial interactionbetween surfaces, such that there may be vector forces in other than theshear/axial direction. The round thread profile may create radial load(instead of shear) across the thread root. As such, the rounded threadprofile may also allow distribution of forces along more threadsurface(s). As composite material is typically best suited forcompression, this allows smaller components and added thread strength.This beneficially provides upwards of 5-times strength in the threadprofile as compared to conventional composite tool connections.

With particular reference to FIG. 3C, the mandrel 314 may have a ballseat 386 disposed therein. In some embodiments, the ball seat 386 may bea separate component, while in other embodiments the ball seat 386 maybe formed integral with the mandrel 314. There also may be a drop ballseat surface 359 formed within the bore 350 at the proximate end 348.The ball seat 359 may have a radius 359A that provides a rounded edge orsurface for the drop ball to mate with. In an embodiment, the radius359A of seat 359 may be smaller than the ball that seats in the seat.Upon seating, pressure may “urge” or otherwise wedge the drop ball intothe radius, whereby the drop ball will not unseat without an extraamount of pressure. The amount of pressure required to urge and wedgethe drop ball against the radius surface, as well as the amount ofpressure required to unwedge the drop ball, may be predetermined. Thus,the size of the drop ball, ball seat, and radius may be designed, asapplicable.

The use of a small curvature or radius 359A may be advantageous ascompared to a conventional sharp point or edge of a ball seat surface.For example, radius 359A may provide the tool with the ability toaccommodate drop balls with variation in diameter, as compared to aspecific diameter. In addition, the surface 359 and radius 359A may bebetter suited to distribution of load around more surface area of theball seat as compared to just at the contact edge/point of other ballseats.

The drop ball (or “frac ball”) may be any type of ball apparent to oneof skill in the art and suitable for use with embodiments disclosedherein. Although nomenclature of ‘drop’ or ‘frac’ ball is used, any suchball may be a ball held in place or otherwise positioned within adownhole tool.

The drop ball may be a “smart” ball (not shown here) configured tomonitor or measure downhole conditions, and otherwise convey informationback to the surface or an operator, such as the ball(s) provided byAquanetus Technology, Inc. or OpenField Technology.

In other aspects, drop ball may be made from a composite material. In anembodiment, the composite material may be wound filament. Othermaterials are possible, such as glass or carbon fibers, phenolicmaterial, plastics, fiberglass composite (sheets), plastic, etc.

The drop ball may be made from a dissolvable material, such as that asdisclosed in co-pending U.S. patent application Ser. No. 15/784,020, andincorporated herein by reference as it pertains to dissolvablematerials. The ball may be configured or otherwise designed to dissolveunder certain conditions or various parameters, including those relatedto temperature, pressure, and composition.

Referring now to FIGS. 4A and 4B together, a longitudinalcross-sectional view and an isometric view of a seal element (and itssubcomponents), respectively, usable with a downhole tool in accordancewith embodiments disclosed herein are shown. The seal element 322 may bemade of an elastomeric and/or poly material, such as rubber, nitrilerubber, Viton or polyurethane, and may be configured for positioning orotherwise disposed around the mandrel (e.g., 214, FIG. 2C). In anembodiment, the seal element 322 may be made from 75 to 80 Duro Aelastomer material. The seal element 322 may be disposed between a firstslip and a second slip (see FIG. 2C, seal element 222 and slips 234,236).

The seal element 322 may be configured to buckle (deform, compress,etc.), such as in an axial manner, during the setting sequence of thedownhole tool (202, FIG. 2C). However, although the seal element 322 maybuckle, the seal element 322 may also be adapted to expand or swell,such as in a radial manner, into sealing engagement with the surroundingtubular (208, FIG. 2B) upon compression of the tool components. In apreferred embodiment, the seal element 322 provides a fluid-tight sealof the seal surface 321 against the tubular.

The seal element 322 may have one or more angled surfaces configured forcontact with other component surfaces proximate thereto. For example,the seal element may have angled surfaces 327 and 389. The seal element322 may be configured with an inner circumferential groove 376. Thepresence of the groove 376 assists the seal element 322 to initiallybuckle upon start of the setting sequence. The groove 376 may have asize (e.g., width, depth, etc.) of about 0.25 inches.

Slips. Referring now to FIGS. 5A, 5B, 5C, 5D, 5E, 5F, and 5G together,an isometric view, a lateral view, and a longitudinal cross-sectionalview of one or more slips, and an isometric view of a metal slip, alateral view of a metal slip, a longitudinal cross-sectional view of ametal slip, and an isometric view of a metal slip without buoyantmaterial holes, respectively, (and related subcomponents) usable with adownhole tool in accordance with embodiments disclosed herein are shown.The slips 334, 342 described may be made from metal, such as cast iron,or from composite material, such as filament wound composite. Duringoperation, the winding of the composite material may work in conjunctionwith inserts under compression in order to increase the radial load ofthe tool.

Either or both of slips 334, 342 may be made of non-composite material,such as a metal or metal alloys. Either or both of slips 334, 342 may bemade of a reactive material (e.g., dissolvable, degradable, etc.). Inembodiments, the material may be a metallic material, such as analuminum-based or magnesium-based material. The metallic material may bereactive, such as dissolvable, which is to say under certain conditionsthe respective component(s) may begin to dissolve, and thus alleviatingthe need for drill thru. In embodiments, any slip of the toolembodiments disclosed herein may be made of dissolvable aluminum-,magnesium-, or aluminum-magnesium-based (or alloy, complex, etc.)material, such as that provided by Nanjing Highsur Composite MaterialsTechnology Co. LTD.

Slips 334, 342 may be used in either upper or lower slip position, orboth, without limitation. As apparent, there may be a first slip 334,which may be disposed around the mandrel (214, FIG. 2C), and there mayalso be a second slip 342, which may also be disposed around themandrel. Either of slips 334, 342 may include a means for gripping theinner wall of the tubular, casing, and/or well bore, such as a pluralityof gripping elements, including serrations or teeth 398, inserts 378,etc. As shown in FIGS. 5D-5F, the first slip 334 may include rows and/orcolumns 399 of serrations 398. The gripping elements may be arranged orconfigured whereby the slips 334, 342 engage the tubular (not shown) insuch a manner that movement (e.g., longitudinally axially) of the slipsor the tool once set is prevented.

In embodiments, the slip 334 may be a poly-moldable material. In otherembodiments, the slip 334 may be hardened, surface hardened,heat-treated, carburized, etc., as would be apparent to one of ordinaryskill in the art. However, in some instances, slips 334 may be too hardand end up as too difficult or take too long to drill through.

Typically, hardness on the teeth 398 may be about 40-60 Rockwell. Asunderstood by one of ordinary skill in the art, the Rockwell scale is ahardness scale based on the indentation hardness of a material. Typicalvalues of very hard steel have a Rockwell number (HRC) of about 55-66.In some aspects, even with only outer surface heat treatment the innerslip core material may become too hard, which may result in the slip 334being impossible or impracticable to drill-thru.

Thus, the slip 334 may be configured to include one or more holes 393formed therein. The holes 393 may be longitudinal in orientation throughthe slip 334. The presence of one or more holes 393 may result in theouter surface(s) 307 of the metal slips as the main and/or majority slipmaterial exposed to heat treatment, whereas the core or inner body (orsurface) 309 of the slip 334 is protected. In other words, the holes 393may provide a barrier to transfer of heat by reducing the thermalconductivity (i.e., k-value) of the slip 334 from the outer surface(s)307 to the inner core or surfaces 309. The presence of the holes 393 isbelieved to affect the thermal conductivity profile of the slip 334,such that that heat transfer is reduced from outer to inner becauseotherwise when heat/quench occurs the entire slip 334 heats up andhardens.

Thus, during heat treatment, the teeth 398 on the slip 334 may heat upand harden resulting in heat-treated outer area/teeth, but not the restof the slip. In this manner, with treatments such as flame (surface)hardening, the contact point of the flame is minimized (limited) to theproximate vicinity of the teeth 398.

With the presence of one or more holes 393, the hardness profile fromthe teeth to the inner diameter/core (e.g., laterally) may decreasedramatically, such that the inner slip material or surface 309 has a HRCof about ˜15 (or about normal hardness for regular steel/cast iron). Inthis aspect, the teeth 398 stay hard and provide maximum bite, but therest of the slip 334 is easily drillable.

One or more of the void spaces/holes 393 may be filled with useful“buoyant” (or low density) material 400 to help debris and the like belifted to the surface after drill-thru. The material 400 disposed in theholes 393 may be, for example, polyurethane, light weight beads, orglass bubbles/beads such as the K-series glass bubbles made by andavailable from 3M. Other low-density materials may be used.

The advantageous use of material 400 helps promote lift on debris afterthe slip 334 is drilled through. The material 400 may be epoxied orinjected into the holes 393 as would be apparent to one of skill in theart.

The metal slip 334 may be treated with an induction hardening process.In such a process, the slip 334 may be moved through a coil that has acurrent run through it. As a result of physical properties of the metaland magnetic properties, a current density (created by induction fromthe e-field in the coil) may be controlled in a specific location of theteeth 398. This may lend to speed, accuracy, and repeatability inmodification of the hardness profile of the slip 334. Thus, for example,the teeth 398 may have a RC in excess of 60, and the rest of the slip334 (essentially virgin, unchanged metal) may have a RC less than about15.

The slots 392 in the slip 334 may promote breakage. An evenly spacedconfiguration of slots 392 promotes even breakage of the slip 334. Themetal slip 334 may have a body having a one-piece configuration definedby at least partial connectivity of slip material around the entirety ofthe body, as shown in FIG. 5D via connectivity reference line 374. Theslip 334 may have at least one lateral groove 371. The lateral groovemay be defined by a depth 373. The depth 373 may extend from the outersurface 307 to the inner surface 309.

First slip 334 may be disposed around or coupled to the mandrel (214,FIG. 2B) as would be known to one of skill in the art, such as a band orwith shear screws (not shown) configured to maintain the position of theslip 334 until sufficient pressure (e.g., shear) is applied. The bandmay be made of steel wire, plastic material or composite material havingthe requisite characteristics in sufficient strength to hold the slip334 in place while running the downhole tool into the wellbore, andprior to initiating setting. The band may be drillable.

When sufficient load is applied, the slip 334 compresses against theresilient portion or surface of the composite member (e.g., 220, FIG.2C), and subsequently expand radially outwardly to engage thesurrounding tubular (see, for example, slip 234 and composite member 220in FIG. 2C). FIG. 5G illustrates slip 334 may be a hardened cast ironslip without the presence of any grooves or holes 393 formed therein.

The slip 342 may be a one-piece slip, whereby the slip 342 has at leastpartial connectivity across its entire circumference. Meaning, while theslip 342 itself may have one or more grooves 344 configured therein, theslip 342 has no separation point in the pre-set configuration. In anembodiment, the grooves 344 may be equidistantly spaced or cut in thesecond slip 342. In other embodiments, the grooves 344 may have analternatingly arranged configuration. That is, one groove 344A may beproximate to slip end 341 and adjacent groove 344B may be proximate toan opposite slip end 343. As shown in groove 344A may extend all the waythrough the slip end 341, such that slip end 341 is devoid of materialat point 372. The slip 342 may have an outer slip surface 390 and aninner slip surface 391.

Where the slip 342 is devoid of material at its ends, that portion orproximate area of the slip may have the tendency to flare first duringthe setting process. The arrangement or position of the grooves 344 ofthe slip 342 may be designed as desired. In an embodiment, the slip 342may be designed with grooves 344 resulting in equal distribution ofradial load along the slip 342. Alternatively, one or more grooves, suchas groove 344B may extend proximate or substantially close to the slipend 343, but leaving a small amount material 335 therein. The presenceof the small amount of material gives slight rigidity to hold off thetendency to flare. As such, part of the slip 342 may expand or flarefirst before other parts of the slip 342. There may be one or moregrooves 344 that form a lateral opening 394 a through the entirety ofthe slip body. That is, groove 344 may extend a depth 394 from the outerslip surface 390 to the inner slip surface 391. Depth 394 may define alateral distance or length of how far material is removed from the slipbody with reference to slip surface 390 (or also slip surface 391). FIG.5A illustrates the at least one of the grooves 344 may be furtherdefined by the presence of a first portion of slip material 335 a on orat first end 341, and a second portion of slip material 335 b on or atsecond end 343.

The slip 342 may have one or more inner surfaces with varying angles.For example, there may be a first angled slip surface 329 and a secondangled slip surface 333. In an embodiment, the first angled slip surface329 may have a 20-degree angle, and the second angled slip surface 333may have a 40-degree angle; however, the degree of any angle of the slipsurfaces is not limited to any particular angle. Use of angled surfacesallows the slip 342 significant engagement force, while utilizing thesmallest slip 342 possible.

The use of a rigid single- or one-piece slip configuration may reducethe chance of presetting that is associated with conventional sliprings, as conventional slips are known for pivoting and/or expandingduring run in. As the chance for pre-set is reduced, faster run-in timesare possible.

The slip 342 may be used to lock the tool in place during the settingprocess by holding potential energy of compressed components in place.The slip 342 may also prevent the tool from moving as a result of fluidpressure against the tool. The second slip (342, FIG. 5A) may includeinserts 378 disposed thereon. In an embodiment, the inserts 378 may beepoxied or press fit into corresponding insert bores or grooves 375formed in the slip 342.

Referring now to FIGS. 6A, 6B, 6C, 6D, 6E, and 6F together, an isometricview, a longitudinal cross-sectional view, a close-up longitudinalcross-sectional view, a side longitudinal view, a longitudinalcross-sectional view, and an underside isometric view, respectively, ofa composite deformable member 320 (and its subcomponents) usable with adownhole tool in accordance with embodiments disclosed herein, areshown. The composite member 320 may be configured in such a manner thatupon a compressive force, at least a portion of the composite member maybegin to deform (or expand, deflect, twist, unspring, break, unwind,etc.) in a radial direction away from the tool axis (e.g., 258, FIG.2C). Although exemplified as “composite”, it is within the scope of thedisclosure that member 320 may be made from metal, including alloys andso forth. Moreover, as disclosed there may be numerous alternativedownhole tool embodiments that do not require nor need the compositemember 320.

During pump down (or run in), the composite member 320 may ‘flower’ orbe energized as a result of a pumped fluid, resulting in greater run-inefficiency (less time, less fluid required). During the settingsequence, the seal element 322 and the composite member 320 may compresstogether. As a result of an angled exterior surface 389 of the sealelement 322 coming into contact with the interior surface 388 of thecomposite member 320, a deformable (or first or upper) portion 326 ofthe composite member 320 may be urged radially outward and intoengagement the surrounding tubular (not shown) at or near a locationwhere the seal element 322 at least partially sealingly engages thesurrounding tubular. There may also be a resilient (or second or lower)portion 328. In an embodiment, the resilient portion 328 may beconfigured with greater or increased resilience to deformation ascompared to the deformable portion 326.

The composite member 320 may be a composite component having at least afirst material 331 and a second material 332, but composite member 320may also be made of a single material. The first material 331 and thesecond material 332 need not be chemically combined. In an embodiment,the first material 331 may be physically or chemically bonded, cured,molded, etc. with the second material 332. Moreover, the second material332 may likewise be physically or chemically bonded with the deformableportion 326. In other embodiments, the first material 331 may be acomposite material, and the second material 332 may be a secondcomposite material.

The composite member 320 may have cuts or grooves 330 formed therein.The use of grooves 330 and/or spiral (or helical) cut pattern(s) mayreduce structural capability of the deformable portion 326, such thatthe composite member 320 may “flower” out. The groove 330 or groovepattern is not meant to be limited to any particular orientation, suchthat any groove 330 may have variable pitch and vary radially.

With groove(s) 330 formed in the deformable portion 326, the secondmaterial 332, may be molded or bonded to the deformable portion 326,such that the grooves 330 are filled in and enclosed with the secondmaterial 332. In embodiments, the second material 332 may be anelastomeric material. In other embodiments, the second material 332 maybe 60-95 Duro A polyurethane or silicone. Other materials may include,for example, TFE or PTFB sleeve option-heat shrink. The second material332 of the composite member 320 may have an inner material surface 368.

Different downhole conditions may dictate choice of the first and/orsecond material. For example, in low temp operations (e.g., less thanabout 250 F), the second material comprising polyurethane may besufficient, whereas for high temp operations (e.g., greater than about250 F) polyurethane may not be sufficient and a different material likesilicone may be used.

The use of the second material 332 in conjunction with the grooves 330may provide support for the groove pattern and reduce preset issues.With the added benefit of second material 332 being bonded or moldedwith the deformable portion 326, the compression of the composite member320 against the seal element 322 may result in a robust, reinforced, andresilient barrier and seal between the components and with the innersurface of the tubular member (e.g., 208 in FIG. 2B). As a result ofincreased strength, the seal, and hence the tool of the disclosure, maywithstand higher downhole pressures. Higher downhole pressures mayprovide a user with better frac results.

Groove(s) 330 allow the composite member 320 to expand against thetubular, which may result in a formidable barrier between the tool andthe tubular. In an embodiment, the groove 330 may be a spiral (orhelical, wound, etc.) cut formed in the deformable portion 326. In anembodiment, there may be a plurality of grooves or cuts 330. In anotherembodiment, there may be two symmetrically formed grooves 330, as shownby way of example in FIG. 6E. In yet another embodiment, there may bethree grooves 330.

As illustrated by FIG. 6C, the depth d of any cut or groove 330 mayextend entirely from an exterior side surface 364 to an upper sideinterior surface 366. The depth d of any groove 330 may vary as thegroove 330 progresses along the deformable portion 326. In anembodiment, an outer planar surface 364A may have an intersection atpoints tangent the exterior side 364 surface, and similarly, an innerplanar surface 366A may have an intersection at points tangent the upperside interior surface 366. The planes 364A and 366A of the surfaces 364and 366, respectively, may be parallel or they may have an intersectionpoint 367. Although the composite member 320 is depicted as having alinear surface illustrated by plane 366A, the composite member 320 isnot meant to be limited, as the inner surface may be non-linear ornon-planar (i.e., have a curvature or rounded profile).

In an embodiment, the groove(s) 330 or groove pattern may be a spiralpattern having constant pitch (p₁ about the same as p₂), constant radius(r₃ about the same as r₄) on the outer surface 364 of the deformablemember 326. In an embodiment, the spiral pattern may include constantpitch (p₁ about the same as p₂), variable radius (r₁ unequal to r₂) onthe inner surface 366 of the deformable member 326.

In an embodiment, the groove(s) 330 or groove pattern may be a spiralpattern having variable pitch (p₁ unequal to p₂), constant radius (r₃about the same as r₄) on the outer surface 364 of the deformable member326. In an embodiment, the spiral pattern may include variable pitch (p₁unequal to p₂), variable radius (r₁ unequal to r₂) on the inner surface366 of the deformable member 320.

As an example, the pitch (e.g., p₁, p₂, etc.) may be in the range ofabout 0.5 turns/inch to about 1.5 turns/inch. As another example, theradius at any given point on the outer surface may be in the range ofabout 1.5 inches to about 8 inches. The radius at any given point on theinner surface may be in the range of about less than 1 inch to about 7inches. Although given as examples, the dimensions are not meant to belimiting, as other pitch and radial sizes are within the scope of thedisclosure.

In an exemplary embodiment reflected in FIG. 6B, the composite member320 may have a groove pattern cut on a back angle β. A pattern cut orformed with a back angle may allow the composite member 320 to beunrestricted while expanding outward. In an embodiment, the back angle βmay be about 75 degrees (with respect to axis 258). In otherembodiments, the angle β may be in the range of about 60 to about 120degrees

The presence of groove(s) 330 may allow the composite member 320 to havean unwinding, expansion, or “flower” motion upon compression, such as byway of compression of a surface (e.g., surface 389) against the interiorsurface of the deformable portion 326. For example, when the sealelement 322 moves, surface 389 is forced against the interior surface388. Generally, the failure mode in a high pressure seal is the gapbetween components; however, the ability to unwind and/or expand allowsthe composite member 320 to extend completely into engagement with theinner surface of the surrounding tubular.

Referring now to FIGS. 7A and 7B together, an isometric view and alongitudinal cross-sectional view, respectively of a bearing plate 383(and its subcomponents) usable with a downhole tool in accordance withembodiments disclosed herein are shown. The bearing plate 383 may bemade from filament wound material having wide angles. As such, thebearing plate 383 may endure increased axial load, while also havingincreased compression strength.

Because the sleeve (254, FIG. 2C) may held rigidly in place, the bearingplate 383 may likewise be maintained in place. The setting sleeve mayhave a sleeve end 255 that abuts against bearing plate end 284, 384.Briefly, FIG. 2C illustrates how compression of the sleeve end 255 withthe plate end 284 may occur at the beginning of the setting sequence. Astension increases through the tool, an other end 239 of the bearingplate 283 may be compressed by slip 242, forcing the slip 242 outwardand into engagement with the surrounding tubular (208, FIG. 2B).

Inner plate surface 319 may be configured for angled engagement with themandrel. In an embodiment, plate surface 319 may engage the transitionportion 349 of the mandrel 314. Lip 323 may be used to keep the bearingplate 383 concentric with the tool 202 and the slip 242. Small lip 323Amay also assist with centralization and alignment of the bearing plate383.

Referring briefly to FIGS. 7C-7EE together, various views a bearingplate 383 (and its subcomponents) configured with stabilizer pininserts, usable with a downhole tool in accordance with embodimentsdisclosed herein, are shown. When applicable, such as when the downholetool is configured with the bearing plate 383 engaged with a metal slip(e.g., 334, FIG. 5D), the bearing plate 383 may be configured with oneor more stabilizer pins (or pin inserts) 364B.

In accordance with embodiments disclosed herein, the metal slip may beconfigured to mate or otherwise engage with pins 364B, which may aidbreaking the slip 334 uniformly as a result of distribution of forcesagainst the slip 334.

It is believed a durable insert pin 364B may perform better than anintegral configuration of the bearing plate 383 because of the hugemassive forces that may be encountered (i.e., 30,000 lbs).

The pins 364B may be made of a durable metal, composite, etc., with theadvantage of composite meaning the pins 364B may be easily drillable.This configuration may allow improved breakage without impactingstrength of the slip (i.e., ability to hold set pressure). In theinstances where strength is not of consequence, a composite slip (i.e.,a slip more readily able to break evening) could be used—use of metalslip is used for greater pressure conditions/setting requirements.

Referring now to FIGS. 8A and 8B together, an underside isometric viewand a longitudinal cross-sectional view, respectively, of one or morecones 336 (and its subcomponents) usable with a downhole tool inaccordance with embodiments disclosed herein, are shown. In anembodiment, cone 336 may be slidingly engaged and disposed around themandrel (e.g., cone 236 and mandrel 214 in FIG. 2C). Cone 336 may bedisposed around the mandrel in a manner with at least one surface 337angled (or sloped, tapered, etc.) inwardly with respect to otherproximate components, such as the second slip (242, FIG. 2C). As such,the cone 336 with surface 337 may be configured to cooperate with theslip to force the slip radially outwardly into contact or grippingengagement with a tubular, as would be apparent and understood by one ofskill in the art.

During setting, and as tension increases through the tool, an end of thecone 336, such as second end 340, may compress against the slip (seeFIG. 2C). As a result of conical surface 337, the cone 336 may move tothe underside beneath the slip, forcing the slip outward and intoengagement with the surrounding tubular (see FIG. 2A). A first end 338of the cone 336 may be configured with a cone profile 351. The coneprofile 351 may be configured to mate with the seal element (222, FIG.2C). In an embodiment, the cone profile 351 may be configured to matewith a corresponding profile 327A of the seal element (see FIG. 4A). Thecone profile 351 may help restrict the seal element from rolling over orunder the cone 336.

Referring now to FIGS. 9A and 9B, an isometric view, and a longitudinalcross-sectional view, respectively, of a lower sleeve 360 (and itssubcomponents) usable with a downhole tool in accordance withembodiments disclosed herein, are shown. During setting, the lowersleeve 360 will be pulled as a result of its attachment to the mandrel214. As shown in FIGS. 9A and 9B together, the lower sleeve 360 may haveone or more holes 381A that align with mandrel holes (281B, FIG. 2C).One or more anchor pins 311 may be disposed or securely positionedtherein. In an embodiment, brass set screws may be used. Pins (orscrews, etc.) 311 may prevent shearing or spin off during drilling.

As the lower sleeve 360 is pulled, the components disposed about mandrelbetween the may further compress against one another. The lower sleeve360 may have one or more tapered surfaces 361, 361A which may reducechances of hang up on other tools. The lower sleeve 360 may also have anangled sleeve end 363 in engagement with, for example, the first slip(234, FIG. 2C). As the lower sleeve 360 is pulled further, the end 363presses against the slip. The lower sleeve 360 may be configured with aninner thread profile 362. In an embodiment, the profile 362 may includerounded threads. In another embodiment, the profile 362 may beconfigured for engagement and/or mating with the mandrel (214, FIG. 2C).Ball(s) 364 may be used. The ball(s) 364 may be for orientation orspacing with, for example, the slip 334. The ball(s) 364 and may alsohelp maintain break symmetry of the slip 334. The ball(s) 364 may be,for example, brass or ceramic.

Referring briefly to FIGS. 9C-9E together, an isometric, lateral, andlongitudinal cross-sectional view, respectively, of the lower sleeve 360configured with stabilizer pin inserts, and usable with a downhole toolin accordance with embodiments disclosed herein, are shown. In additionto the ball(s) 364, the lower sleeve 360 may be configured with one ormore stabilizer pins (or pin inserts) 364A.

A possible difficulty with a one-piece metal slip is that instead ofbreaking evenly or symmetrically, it may be prone to breaking in asingle spot or an uneven manner, and then fanning out (e.g., like a fanbelt). If this it occurs, it may problematic because the metal slip(e.g., 334, FIG. 5D) may not engage the casing (or surrounding surface)in an adequate, even manner, and the downhole tool may not be secured inplace. Some conventional metal slips are “segmented” so the slip expandsin mostly equal amounts circumferentially; however, it is commonlyunderstood and known that these type of slips are very prone topre-setting or inadvertent setting.

In contrast, the one-piece slip configuration is very durable, takes alot of shock, and will not readily pre-set, but may require aconfiguration that urges uniform and even breakage. In accordance withembodiments disclosed herein, the metal slip 334 may be configured tomate or otherwise engage with pins 364A, which may aid breaking the slip334 uniformly as a result of distribution of forces against the slip334.

It is plausible a durable insert pin 364A may perform better than anintegral pin/sleeve configuration of the lower sleeve 360 because of thehuge massive forces that are encountered (i.e., 30,000 lbs). The pins364A may be made of a durable metal, composite, etc., with the advantageof composite meaning the pins 364A are easily drillable.

This configuration is advantageous over changing breakage points on themetal slip because doing so would impact the strength of the slip, whichis undesired. Accordingly, this configuration may allow improvedbreakage without impacting strength of the slip (i.e., ability to holdset pressure). In the instances where strength is not of consequence, acomposite slip (i.e., a slip more readily able to break evening) couldbe used—use of metal slip is typically used for greater pressureconditions/setting requirements.

The pins 364A may be formed or manufactured by standard processes, andthen cut (or machined, etc.) to an adequate or desired shape, size, andso forth. The pins 364A may be shaped and sized to a tolerance fit withslots 381B. In other aspects, the pins 364A may be shaped and sized toan undersized or oversized fit with slots 381B. The pins 364A may beheld in situ with an adhesive or glue.

In embodiments one or more of the pins 364, 364A may have a rounded orspherical portion configured for engagement with the metal slip (seeFIG. 3D). In other embodiments, one or more of the pins 364, 364A mayhave a planar portion 365 configured for engagement with the metal slip334. In yet other embodiments, one or more of the pins 364, 364A may beconfigured with a taper(s) 369.

The presence of the taper(s) 369 may be useful to help minimizedisplacement in the event the metal slip 334 inadvertently attempts to‘hop up’ over one of the pins 364A in the instance the metal slip 334did not break properly or otherwise.

One or more of the pins 364A may be configured with a ‘cut out’ portionthat results in a pointed region on the inward side of the pin(s) 364A(see 7EE). This may aid in ‘crushing’ of the pin 364A during setting sothat the pin 364A moves out of the way.

Referring briefly to FIGS. 12A-12B, an isometric and lateral side viewof a metal slip according to embodiments of the disclosure, are shown.FIGS. 12A and 12B together show one or more of the (mating) holes 393Ain the metal slip 334 may be configured in a round, symmetrical fashionor shape. The holes 393A may be notches, grooves, etc. or any otherreceptacle-type shape and configuration.

A downhole tool of embodiments disclosed herein may include the metalslip 334 disposed, for example, about the mandrel. The metal slip 334may include (prior to setting) a one-piece circular slip bodyconfiguration. The metal slip 334 may include a face 397 configured witha set or plurality of mating holes 393A. FIGS. 12A and 12B illustratethere may be three mating holes 393A. Although not limited to any oneparticular arrangement, the holes 393A may be disposed in a generally orsubstantially symmetrical manner (e.g., equidistant spacing around thecircumferential shape of the face 397). In addition, althoughillustrated as generally the same size, one or more holes may vary insize (e.g., dimensions of width, depth, etc.). FIG. 12G illustrates anembodiment where the metal slip 334 may include a set of mating holeshaving four mating holes. As shown, one or more of the mating holes 393Aof the set of mating holes may be circular or rounded in shape.

Referring now to FIG. 12C, a lateral view of a metal slip engaged with asleeve according to embodiments of the disclosure, is shown. Asillustrated, an engaging body or surface of a downhole tool, such as asleeve 360 may be configured with a corresponding number of stabilizerpins 364A. Thus, for example, the sleeve 360 may have a set ofstabilizer pins to correspond to the set of mating holes of the slip334. In other aspects, the set of mating holes 393A comprises threemating holes, and similarly the set of stabilizer pins comprises threestabilizer pins 364A, as shown in the Figure. The set of mating holesmay be configured in the range of about 90 to about 120 degreescircumferentially (e.g., see FIG. 12G, arcuate segment 393B being about90 degrees). In a similar fashion, the set of stabilizer pins 364A maybe arranged or positioned in the range of about 90 to about 120 degreescircumferentially around the sleeve 360.

Thus, in accordance with embodiments of the disclosure the metal slip334 may be configured for substantially even breakage of the metal slipbody during setting. Prior to setting the metal slip 334 may have aone-piece circular slip body. That is, at least some part or aspects ofthe slip 334 has a solid connection around the entirety of the slip.

In an embodiment, the face (397, FIG. 12A) may be configured with atleast three mating holes 393A. In embodiments, the sleeve 360 may beconfigured or otherwise fitted with a set of stabilizer pins equal innumber and corresponding to the number of mating holes 393A. Thus, eachpin 364A may be configured to engage a corresponding mating hole 393A.Although not meant to be limited, there may be about three to fivemating holes and corresponding pins.

The downhole tool may be configured for at least three portions of themetal slip 334 to be in gripping engagement with a surrounding tubularafter setting. The set of stabilizer pins may be disposed in asymmetrical manner with respect to each other. The set of mating holesmay be disposed in a symmetrical manner with respect to each other.

In accordance with embodiments disclosed herein, the metal slip 334 maybe configured to mate or otherwise engage with pins 364A, which may aidbreaking the slip 334 uniformly as a result of distribution of forcesagainst the slip 334. The sleeve 360 may include a set of stabilizerpins configured to engage the set of mating holes.

FIGS. 12D-12F illustrate a lateral ‘slice’ view through the metal slip334 as the pin 364 a induces fracture of the slip body.

Referring briefly to FIGS. 13A-13D, one or more of the (mating) holes393A in the metal slip 334 may be configured in a round, symmetricalfashion or shape. Just the same, one or more of the holes 393A mayadditionally or alternatively be configured in an asymmetrical fashionor shape. In an embodiment, one or more of the holes may be configuredin a ‘tear drop’ fashion or shape.

Each of these aspects may contribute to the ability of the metal slip334 to break a generally equal amount of distribution around the slipbody circumference. That is, the metal slip 334 breaks in a manner whereportions of the slip engage the surrounding tubular and the distributionof load is about equal or even around the slip 334. Thus, the metal slip334 may be configured in a manner so that upon breakage load may beapplied from the tool against the surrounding tubular in an approximateeven or equal manner circumferentially (or radially).

The metal slip 334 may be configured in an optimal one-piececonfiguration that prevents or otherwise prohibits pre-setting, butultimately breaks in an equal or even manner comparable to the intent ofa conventional “slip segment” metal slip.

Referring now to FIGS. 14A, 14B, and 14C together, an isometric view, alongitudinal side view, and a component breakout view, respectively, ofa downhole tool with a wedge mandrel, in accordance with embodimentsdisclosed herein, are shown.

Downhole tool 2102 may be run, set, and operated as described herein andin other embodiments (such as in System 200, and so forth), and asotherwise understood to one of skill in the art. Components of thedownhole tool 2102 may be arranged and disposed about a wedge mandrel2114, as described herein and comparable to other embodiments, and asotherwise understood to one of skill in the art. Thus, downhole tool2102 may be comparable or identical in aspects, function, operation,components, etc. as that of other tool embodiments disclosed herein.

All mating surfaces of the downhole tool 2102 may be configured with anangle, such that corresponding components may be placed undercompression instead of shear. The wedge mandrel 2114 may extend throughthe tool (or tool body) 2102, and include a flowpath (or bore, flowbore,inner bore, etc.) 2151 formed therein (e.g., an axial bore).

The wedge mandrel 2114 may be made of a material as described herein andin accordance with embodiments of the disclosure, such as a compositefilament wound material made by the Applicant. The wedge mandrel 2114may be made other materials, such as a metallic material, for example,an aluminum-based, magnesium-based, or aluminum-magnesium-basedmaterial. The metallic material may be reactive, such as dissolvable,which is to say under certain conditions that wedge mandrel 2114 maybegin to dissolve, and thus alleviating the need for drill thru.

In embodiments, the wedge mandrel 2114 may be made of dissolvablealuminum-, magnesium-, or aluminum-magnesium-based (or alloy, complex,etc.) material, such as that provided by Nanjing Highsur CompositeMaterials Technology Co. LTD.

Just the same, the wedge mandrel may be made of reactive compositematerial formed (cured) from an initial mixture composition ofembodiments herein.

Other components may be made of non-composite material, such as a metalor metal alloys. In embodiments, the material may be a metallicmaterial, such as an aluminum-based or magnesium-based material. Themetallic material may be reactive, such as dissolvable, which is to sayunder certain conditions the respective component(s) may begin todissolve, and thus alleviating the need for drill thru.

Downhole tool 2102 may include a lower sleeve 2160 disposed around thewedge mandrel 2114. The lower sleeve 2160 may be threadingly engagedwith the mandrel 2114. As a support platform 2121 is pulled in tension,various components disposed about mandrel 2114 between the supportplatform 2121 and a setting sleeve (2154, FIG. 22A) may begin tocompress against one another. This force and resultant movement mayultimately cause compression and expansion of a seal element 2122

Additional tension or load may be applied to the tool 2102 that resultsin movement of the wedge mandrel 2114 against a fingered member 2176.Accordingly, via interaction with angled surfaces of each other, one ormore ends 2715 of the fingered member 2176 may be urged radially outwardand into engagement with a tubular (2108). The fingered member 2176 maybe movingly (such as slidingly) engaged and disposed around the wedgemandrel 2114.

The setting sleeve (2154) may engage against a shoulder 2184 of thewedge mandrel 2114, which may accommodate to or provide ability for thetransfer of load through the rest of the tool 2102. The setting sleevemay be a grooved setting sleeve in accordance with embodiments herein.

Although many configurations are possible, the fingered member 2176 maygenerally have a circular body (or ring shaped) portion 2195 configuredfor positioning on or disposal around the wedge mandrel 2114. Extendingfrom the circular body portion may be two or more fingers (dogs,protruding members, etc.) 2177. In the assembled tool configuration, thefingers 2177 may be referred to as facing “uphole” or toward the top(proximate end) of the tool 2102.

The fingered member 2176 may include a plurality of fingers 2177. Inembodiments, there may be a range of about 6 to about 12 fingers 2177.The fingers 2177 may be configured symmetrically and equidistantly toeach other. As the fingers 2177 are urged outwardly they may provide asynergistic effect of centralizing the downhole tool 2102, which may beof greater benefit in situations where the surrounding tubular has ahorizontal orientation.

Fingers 2177 may be formed with a gap or separation point 2181therebetween. The size of the fingers 2177 in terms of width, length,and thickness, and the number of fingers 2177 may be optimized in amanner that results in the greatest ability to seal an annulus (2190,compare FIGS. 22A and 22C).

During setting, the fingered member 2176 (including fingers 2177) may beurged along a proximate surface 2149 (or vice versa, the proximatesurface 2149 may be urged against an underside of the fingered member2176). The proximate surface 2149 may be an angled surface or taper ofwedge mandrel 2114. Other components may be positioned proximate to theunderside (or end 2175) of fingered member 2175, such as an insert 2199.As the fingered member 2176 and the surface 2149 are urged together, thefingers 2177 may be resultantly urged radially outward toward the innersurface of the tubular (2108, FIG. 22A). One or more ends 2175 ofcorresponding fingers 2177 may eventually come into contact with thetubular (see contact point 2186). Ends 2175 (of fingers) may beconfigured (such as by machining) with an end taper 2174.

The use of an end taper 2174 may be multipurpose. For example, if thetool 2102 needs to be removed (or moved uphole) prior to setting, theends 2175 of the fingers 2177 may be less prone to catching on surfacesas the tool 2102 moves uphole. In addition, the ends 2175 of the fingers2175 may have more surface area contact with the tubular.

The surface 2149 may be smooth and conical in nature, which may resultin smooth, linear engagement with the fingered member 2176. The angledsurface 2149 may transition to a more or less axial surface 2149 a(i.e., a surface that is about parallel to a longitudinal axis 2158).

In aspects, the outer surface of the wedge mandrel 2114 may beconfigured with a detent (or notch) 2170, approximately at thetransition point from angled surface 2149 to axial surface 2149 a. Inthe assembled position, the ends 2175 of the fingers 2177 may reside orbe positioned within or proximate to the detent 2170. The arrangement ofthe ends 2175 within the detent 2170 may prevent inadvertent operationof the fingered member 2176. In this respect, a certain amount ofsetting force is required to “bump” the ends of the fingers 2177 out ofand free of the detent 2170 so that the fingered member 2176 and thesurface 2149 can be urged together, and the fingers 2177 extendedoutwardly. As shown in FIGS. 14A and 14B, the insert 2199 may bedirectly proximate to the detent 2170, and thus between the detent 2170and the finger ends 2177. In this respect, a certain amount of settingforce may be required to “bump” the insert 2199 out of and free of thedetent 2170 so that it may be urged along the surface 2149.

The fingered member 2176 may be referred to as having a “transitionzone” 2110, essentially being the part of the member where the fingers2177 begin to extend away from the body 2195. In this respect, thefingers 2177 are connected to or integral with the body 2195. Inoperation as the fingers 2177 are urged radially outward, a flexing (orpartial break or fracture) may occur within the transition zone 2110.The transition zone 2110 may include an outer surface 2137 and innersurface 2129. The outer surface 2137 and inner surface 2129 may beseparated by a portion or amount of material 2185. The fingered member2176 may be configured so that flexing, break or fracture may occur orotherwise be promoted within the material 2185. Flexing or fracture maybe induced within the material as a result of one or more grooves. Forexample, the inner surface 2137 may have a first finger groove 2111. Theouter surface 2137 may in addition or alternatively have a fingergroove, such as a second finger groove 2113.

The presence of the material 2185 may provide a natural “hinge” effectwhereby the fingers 2177 become moveable from the body (ring) 2195, suchas when the fingered member 2176 is urged against surface 2149. Aftersetting one or more fingers 2177 may remain at least partially connectedwith body 2195 in the transition zone 2110. The presence of the material2185 may promote uniform flexing of the fingers 2177. The length of thefingers 2177 and/or amount of material 2185 are operational variablesthat may be modified to suit a particular need for a respective annulussize.

Upon setting, there may be a seal 2125 formed in tool annulus 2190. Aside 2115 of the shoulder 2184 may act as a stop against componentstherebelow, including a backup ring 2157 a. Thus, the compressionbetween the seal element 2122 and the backup rings 2157 a,b maycontribute to the formed seal. The formed seal 2125 may withstandpressurization of greater than 10,000 psi. In an embodiment, the seal2125 withstands pressurization in the range of about 5,000 psi to about15,000 psi.

The Figures illustrate the downhole tool 2102 may include othercomponents, such as the seal element 2122. The seal element 2122 may bemade of an elastomeric and/or poly material, such as rubber, nitrilerubber, Viton or polyurethane, and may be configured for positioning orotherwise disposed around the wedge mandrel 2114. The seal element 2122may have an inner circumferential groove 2123. The presence of thegroove 2123 may assist the seal element 2122 to initially buckle uponstart of the setting sequence. The groove 2123 may have a size (e.g.,width, depth, etc.) of about 0.25 inches.

On either side of the seal element may be a backup ring. As shown theremay be a first backup ring 2157 a and a second backup ring 2157 b. Inthe assembled configuration, the insert 2199 may be positioned betweenthe ends 2175 of the fingers 2177 and the second backup ring 2157 b.

The fingers 2177 may have a respective gripper insert 2191 fitted orotherwise disposed therein. Although not limited to any particularnumber, type or size, there may be a respective gripper insert 2191disposed in the finger(s) 2177. The gripper insert 2191 may bepositioned within a window (or hole, opening, etc.) 2188 formed in anyrespective finger 2177. Although not necessary, the window 2188 mayextend the entire depth of the thickness of the finger 2177. In thisrespect, the gripper insert 2191 may be positioned therein, wherein itsunderside may be proximate to the wedge mandrel outer surface. Althoughillustrated as such, every finger 2177 need not have a window 2188and/or gripper insert 2191. Moreover, the fingers 2177 need not have anywindows 2188 and/or inserts 2191 at all. Although not shown here,buttons 2180 may be disposed directly into the fingers 2177.

The fingered member 2176 may have one or more recessed regions (or hole,opening, etc.) 2128 to accommodate respective dogs 2120 of the supportplatform 2121. Similarly, the wedge mandrel 2114 may have one or moremandrel windows 2119 also to accommodate respective dogs 2120 of thesupport platform 2121.

Components of the downhole tool 2102 may be arranged and disposed aboutthe wedge mandrel 2114, as described herein and in other embodiments,and as otherwise understood to one of skill in the art. Thus, downholetool 2102 may be comparable or identical in aspects, function,operation, components, etc. as that of other tool embodiments providedfor herein, and redundant discussion is limited for sake of brevity,while structural (and functional) differences are discussed in withdetail, albeit in a non-limiting manner.

The tool 2102 may be deployed and set with a conventional setting tool(not shown) such as a Model 10, 20 or E-4 Setting Tool available fromBaker Oil Tools, Inc., Houston, Tex. Once the tool 2102 reaches the setposition within the tubular, the setting mechanism or workstring may bedetached from the tool 2102 by various methods, resulting in the tool2102 left in the surrounding tubular and one or more sections of thewellbore isolated.

Referring now to FIGS. 15A and 15B together, an isometric view and alongitudinal side cross-sectional view of a wedge mandrel usable with adownhole tool, in accordance with embodiments disclosed herein, areshown. Components of the downhole tool may be arranged and disposedabout the wedge mandrel 2114, as described and understood to one ofskill in the art, and may be comparable to other embodiments disclosedherein (e.g., see downhole tool 202 with mandrel 214).

The wedge mandrel 2114, which may be made from filament wound drillablematerial, may have a distal end 2146 and a proximate end 2148. Thefilament wound material may be made of various angles as desired toincrease strength of the wedge mandrel 2114 in axial and radialdirections.

The wedge mandrel 2114 may include a flowpath (or bore, flowbore, etc.)2151 formed therethrough (e.g., an axial bore). The 2151, for example anaxial bore, may extend through the entire wedge mandrel 2114, withopenings at both the proximate end 2148 and oppositely at its distal end2146. Accordingly, the wedge mandrel 2114 may have an inner bore surface2147, which may include one or more threaded surfaces 2116 formedthereon.

The ends 2146, 2148 of the wedge mandrel 2114 may include internal orexternal (or both) threaded portions. As shown, the wedge mandrel 2114may have internal threads 2116 within the bore 2151 configured toreceive a ball seat insert (not shown here). In an embodiment, the firstset of threads 2116 may be rounded threads.

The outer surface of the wedge mandrel 2114 may include a neck ortransition portion surface 2149, such that the mandrel may havevariation with its outer diameter. In an embodiment, the wedge mandrel2114 may have a first outer diameter D21 that is greater than a secondouter diameter D22. The transition surface may have an angle withrespect to the tool (or tool component axis). The angled surface 2149may end or otherwise transition to an axial external surface 2149 a.There may be a bump or detent 2170 formed therebetween.

In addition to the first set of threads 2116, the wedge mandrel 2114 mayhave a second set of threads 2117. In one embodiment, the second set ofthreads 2117 may be rounded threads disposed along an external mandrelsurface at the distal end 346. The use of rounded threads may increasethe strength of the threaded connection.

For example, when mated with a lower sleeve (2160) having correspondingrounded threads, this may result in distribution of load forces alongthe threaded connection therebetween at an angle away from the longaxis. Accordingly, the use of round threads may allow a non-axialinteraction between surfaces, such that there may be vector forces inother than the shear/axial direction. The round thread profile maycreate radial load (instead of shear) across the thread root. As such,the rounded thread profile may also allow distribution of forces alongmore thread surface(s). As composite material is typically best suitedfor compression, this allows smaller components and added threadstrength. This beneficially provides upwards of 5-times strength in thethread profile as compared to conventional composite tool connections.

Although described and shown as rounded, the threads 2116 and 2117 couldbe other thread profiles, including those suitable for use in filamentwound composite material.

The wedge mandrel 2114 may have a shoulder 2184 on the proximate end2148. One side of the shoulder 2184 may be compressible against an end(2155) of a setting sleeve (2154) during setting. Another side 2115 ofthe shoulder 2184 may act as a stop against components therebelow,including a backup ring 2157 a.

On occasion it may be necessary or otherwise desired to produce a fluidfrom the formation while leaving a set plug in place. The ID of aconventional bore size (1 inch or less) is normally adequate to allowdrop balls to pass therethrough, but may be inadequate for production.In order to produce desired fluid flow, it often becomes necessary todrill out a set tool—this requires a stop in operations, rig time, drilltime, and related operator and equipment costs.

On the other hand, the presence of the oversized ID 2131 of bore 2151,and thus a larger cross-sectional area as compared to bore 250, provideseffective and efficient production capability through the tool 2102without the need to resort to drilling of the tool. The ID 2131 may bein the range of about greater than 1 inch to less than 4 inches. In anembodiment, the ID 2131 may be between about 2 inches to about 3 inches.

The wedge mandrel 2114 may include one or more mandrel windows (orslots, etc.) 2119 formed therein. Although not meant to be limited toany particular size or shape, FIGS. 15A-15B show there may be aboutthree windows 2119, which may be generally rectangular in nature.

Although not shown here, it may be the case that the end 2148 of thewedge mandrel may be configured with a respective wedge mandrel ballseat. One of skill would appreciate a larger ball (as compared to ball2163) may be needed. In embodiments, such a ball may have a diameter ofabout 2 inches to about 4 inches.

Referring now to FIGS. 16A and 16B together, an isometric view and alongitudinal side cross-sectional view of a ball seat insert usable witha downhole tool, in accordance with embodiments disclosed herein, areshown. The ball seat insert 2135 may be a generally frustoconcial shapedcomponent configured for engagement into the wedge mandrel (2114).

For a downhole tool where there is no concern over bore size, a ballseat may be formed into the mandrel. However, where large bore size(i.e., to accommodate production) is desired, this would require a largediameter ball seat, along with reduced wall thickness of the mandrel.This may be structurally limiting, and so use of the ball seat insert2135 may be useful to overcome these shortcomings (see FIG. 22C wherethe ball seat insert provides axial support against radial forcesincurred during setting of the downhole tool 2102, and radial supportfor pressure/collapse).

In embodiments, the ball seat insert 2135 may be made of dissolvablealuminum-, magnesium-, or aluminum-magnesium-based (or alloy, complex,etc.) material, such as that provided by Nanjing Highsur CompositeMaterials Technology Co. LTD. Just the same, the insert 2135 may be madeof reactive composite material formed from an initial mixturecomposition of embodiments herein. As another example, the ball seat maybe made of a metal material like that produced by Bubbletight, LLC ofNeedville, Tex., as would be apparent to one of skill in the art,including fresh-water reactive composite metal, ambient-temperaturefresh-water reactive composite metal, ambient-temperature fresh-waterreactive elastomeric polymer, and high-strength brine-degradablereactive metal.

Other components may be made of materials as described herein, includingreactive composite, cured, and metal materials.

Generally speaking, the material of ball seat insert 2135 may beconfigured to react. The time to react from start to finish (i.e., tothe point where the ball seat insert no longer has a durable threadedconnection with the wedge mandrel—see FIG. 22D) may be in the range ofabout 3 hours to about 48 hours.

The ball seat insert 2135 may be configured to include one or more holes2130 formed therein. Although not meant to be limited to any particularnumber, shape, orientation, or size, the holes 2130 may be longitudinalin orientation through the insert 2135. The presence of one or moreholes 2130 may result in the surface(s) of the insert 2135 havinggreater exposure to the fluid that promotes reactivity of the material.One or more holes 2130 may extend entirely through the ball seat insert.However, other holes 2130 may only extend to a certain depth, such asshown in FIG. 16B. The holes 2130 may be optimized to promote the mostsurface contact, yet at the same time not detract from the durabilityand pressure integrity of the insert 2135.

The ball seat insert 2135 may have a set of insert threads 2145. Theinsert threads 2145 may be configured to mate with corresponding threads(i.e., 2116) of the wedge mandrel (2114). Although not meant to belimited, the threads 2145 may be rounded threads.

The ball seat insert 2135 may have an insert hollow or bore 2139, whichmay be suitable for the adapter shaft (2153) to pass therethrough. Thewider end of the insert 2135 may have an insert groove 2142, which maybe generally circumferential in nature. The insert groove 2142 may besuitable for fitting an O-ring therein.

The insert 2135 may be configured with a ball seat surface 2159 suchthat a drop ball may come to rest and seat at in the seat. Asapplicable, the drop ball (not shown here) may be lowered into thewellbore and flowed toward the drop ball seat 2159. Alternatively, theball may be held within the tool during run-in, thus alleviating theneed for flowdown. The ball seat 2159 may be formed with a radius 2159 a(i.e., circumferential rounded edge or surface).

Referring now to FIGS. 17A and 17B together, an isometric view and alongitudinal side cross-sectional view of a fingered member usable witha downhole tool, in accordance with embodiments disclosed herein, areshown. Although many configurations are possible, the fingered member2176 may generally have a circular body (or ring shaped) portion 2195configured for positioning on or disposal around the wedge mandrel(2114). Extending from the circular body portion may be two or morefingers (dogs, protruding members, etc.) 2177. Although not meant to belimiting, the fingered member 2176 may be made from a filament woundcomposite material in accordance with embodiments herein, and as wouldbe apparent to one of skill in the art. The fingered member 2176 may bemade from a reactive material, such as that made from an initial mixturecomposition described herein. The reactive material may be a curedmaterial.

The fingered member 2176 may include a plurality of fingers 2177. Inembodiments, there may be a range of about 6 to about 12 fingers 2177.The fingers 2177 may be configured symmetrically and equidistantly toeach other. Fingers 2177 may be formed with a gap or separation point2181 therebetween. The size of the fingers 2177 in terms of width,length, and thickness, and the number of fingers 2177 may be optimizedin a manner that results in the greatest ability to seal an annulus(2190, compare FIGS. 22A and 22C). Ends 2175 (of fingers) may beconfigured (such as by machining) with an end taper 2174.

The fingered member 2176 may be referred to as having a “transitionzone” 2110, essentially being the part of the member where the fingers2177 begin to extend away from the body 2195. In this respect, thefingers 2177 are connected to or integral with the body 2195. Inoperation as the fingers 2177 are urged radially outward, a flexing (orpartial break or fracture) may occur within the transition zone 2110.The transition zone 2110 may include an outer surface 2137 and innersurface 2129. The outer surface 2137 and inner surface 2129 may beseparated by a portion or amount of material 2185. The fingered member2176 may be configured so that the flexing, break or fracture occurswithin the material 2185. Flexing or fracture may be induced within thematerial as a result of one or more grooves.

The fingers 2177 may have a respective gripper insert or carriage 2191fitted or otherwise disposed therein. Although not limited to anyparticular number, type or size, there may be a respective gripperinsert 2191 disposed in the finger(s) 2177.

In embodiments, the gripper insert 2191 may be a poly-moldable material.In other embodiments, the gripper insert 2191 may be a durable metal,such as cast iron. In aspects, the insert 2191 may be hardened, surfacehardened, heat-treated, carburized, etc., as would be apparent to one ofordinary skill in the art. FIG. 17C illustrates the gripper insert 2191disposed in the finger end 2175 as being configured with serrated teeth2198.

The gripper insert 2191 may be treated with an induction hardeningprocess. In such a process, block or ring of metal may be moved througha coil that has a current run through it. As a result of physicalproperties of the metal and magnetic properties, a current density(created by induction from the e-field in the coil) may be controlled ina specific location. The insert 2191 may be machined from this treatedmetal. Such a process may lend to speed, accuracy, and repeatability inmodification of the hardness profile of the gripper insert 2191. Assuch, for example, the teeth 2198 may have a RC in excess of 60, and therest of the insert 2191 (essentially virgin, unchanged metal) may have aRC less than about 15. In embodiments the gripper insert 2191 may bemade of a reactive material in accordance with embodiments herein.

During heat treatment of the insert itself, the teeth 2198 may heat upand harden resulting in heat-treated outer area/teeth, but not the restof the insert. In this manner, with treatments such as flame (surface)hardening, the contact point of the flame is minimized (limited) to theproximate vicinity of the teeth 2198. Serrated outer surfaces or teeth2198 of the may be configured such that the surfaces 2198 prevent thefingered member (or tool) from moving (e.g., axially or longitudinally)when the tool is set within the surrounding tubular. The use of theinsert 2191 being made of metal provides bite characteristics normallyassociated with a metal slip, while at the same time the material of thefingered member 2176 may be easily drillable composite material.Moreover, the bite area may be enlarged versus that of buttons.

Still, as shown in FIGS. 17A and 17B, the gripper insert 2191 may beconfigured within one more buttons 2180 disposed therein. The buttons2180 may be of any durable material suitable to provide sufficient biteinto a surrounding tubular, such as ceramic or steel. Any button 2180may have a flat surface or concave surface. In an embodiment, theconcave surface may include a depression formed therein. One or more ofthe buttons 2180 may have a sharpened (e.g., machined) edge or corner2182, which allows the button 2180 greater biting ability.

The gripper insert 2191 may be positioned within a window (or hole,opening, etc.) 2188 formed in any respective finger 2177. Although notnecessary, the window 2188 may extend the entire depth of the thicknessof the finger 2177. In this respect, the gripper insert 2191 may bepositioned therein, wherein its underside may be proximate to the wedgemandrel outer surface. The insert 2191 may have a tight tolerance fitwith the window 2188. To aid securing the insert 2188 therein, anadhesive or the like may be used.

Briefly, an underside of the insert 2191 may be configured with anabrasive surface 2183, such as that shown in side view in FIG. 17D (seealso 17B). With respect to FIGS. 17A and 17B, the abrasive surface 2183may be useful for preventing the fingered member 2176 from inadvertentmovement along mandrel surface 2149. In embodiments, the abrasivesurface 2183 may be mini-serrations. One of skill would appreciate thatalthough illustrated as such, every finger 2177 need not have a window2188 and/or gripper insert 2191.

The fingered member 2176 may have one or more recessed regions (or hole,opening, etc.) 2128 to accommodate respective dogs (2120) of a supportplatform (2121). Similarly, the wedge mandrel 2114 may have one or moremandrel windows 2114 also to accommodate respective dogs 2120 of thesupport platform.

Referring now to FIGS. 18A, 18B, and 18C together, a side expanded view,a side collapsed view, and an isometric view, respectively, of aninsert, in accordance with embodiments disclosed herein, are shown. Theinsert 2199 may have a circular body 2187, having a first end 2196 and asecond end 2133.

A groove or winding 2194 may be formed between the first end 2196 andthe second end 2133. As the insert 2199 may be ring-shaped, there may bea hollow 2193 in the body 2187. Accordingly, the insert 2199 may beconfigured for positioning onto and/or around the wedge mandrel (2114).The use of the groove 2194 may be beneficial as while it is desirous forinsert 2199 to have some degree of rigidity, it is also desirous for theinsert 2199 to expand (unwind, flower, etc.) beyond the original OD ofthe tool, including along the angled surface of the wedge mandrel

In this respect, the insert 2199 may be made of a high elongationmaterial (e.g., physical properties of ˜100% elongation). Insert 2199material may be glass or carbon fiber or nanocarbon/nanosilicareinforced. The insert 2199 may durable enough to withstand compressiveforces, but still expand or otherwise unwind upon being urged outwardlyby the wedge mandrel. The insert 2199 may be made of PEEK (polyetherether ketone).

The groove 2194 may be continuous through the body 2197. However, thegroove 2194 may be discontinuous, whereby a plurality of grooves areformed with (or otherwise defined by) a material portion present betweenrespective grooves. The groove(s) 2197 may be helically formed in natureresulting in a ‘spring-like’ insert. An edge 2192 of the first end 2196may be positionable within a notch or detent (2170) of the wedge mandrelAlthough not shown, a filler may be disposed within the groove(s) 2194.Use of the filler may help provide stabilization to the tool (and itscomponents) during run-in. In embodiments, the filler may be made ofsilicone.

To maintain the collapsed position of the insert 2197, a securing member2144 may be used. Accordingly, the insert 2197 may be configured with aninsert bore 2144 a. In an embodiment, the securing member 2144 may be anylon screw.

Referring now to FIGS. 19A and 19B together, an engaged side view and anexploded side view, respectively, of a seal element between a first andsecond backup ring, in accordance with embodiments disclosed herein, areshown.

The seal element 2122 may be made of an elastomeric and/or polymaterial, such as rubber, nitrile rubber, Viton or polyurethane, and maybe configured for positioning or otherwise disposed around the mandrel(e.g., 214, FIG. 2C). In an embodiment, the seal element 322 may be madefrom 75 to 80 Duro A elastomer material. The seal element 322 may bedisposed between a first backup ring 2157 a and a second backup ring2157 b. In a similar manner, the backup rings 2157 a,b may be made of anelastomeric and/or poly material, such as rubber, nitrile rubber, Vitonor polyeurethane. In an embodiment, the backup rings 2157 a,b may bemade from 75 to 80 Duro A elastomer material. In an embodiment, thebackup rings 2157 a,b may be made from PEEK, Teflon, or nylon typematerial.

The seal element 2122 may be configured to buckle (deform, compress,etc.), such as in an axial manner, during the setting sequence of thedownhole tool (202, FIG. 2C). However, although the seal element 2122may buckle, the seal element 2122 may also be adapted to expand orswell, such as in a radial manner, into sealing engagement with thesurrounding upon compression of the tool components. In aspects, theseal element 2122 may be suitable to provide a fluid-tight seal of theseal surface against the tubular. The seal element 322 may be configuredwith an inner circumferential groove (2123, FIG. 14C).

The seal element 2122 may have one or more angled surfaces configuredfor contact with other component surfaces proximate thereto. Forexample, the seal element may have angled surfaces 2140 a and 2140 b.Respective underside grooves (not viewable here) of the first backupring 2157 a and the second backup ring 2157 b may be configured formating with the angled surfaces 2140 a and 2140 b.

Referring now to FIGS. 20A and 20B together, an isometric view and alateral side view of a support platform usable with a downhole tool, inaccordance with embodiments disclosed herein, are shown. The supportplate 2121 may be a generally round shaped component configured forengagement into the wedge mandrel (2114).

During setting, the support plate 2121 will be pulled as a result of itsattachment to the setting tool (via elongated shaft 2153). As thesupport plate 2121 is pulled, the components disposed about the wedgemandrel between the may further compress against one another.

In embodiments, the support plate 2121 may be made of dissolvablealuminum-, magnesium-, or aluminum-magnesium-based (or alloy, complex,etc.) material, such as that provided by Nanjing Highsur CompositeMaterials Technology Co. LTD. Just the same, the support plate 2121 maybe made of reactive composite material formed from an initial mixturecomposition of embodiments herein. As another example, the ball seat maybe made of a metal material like that produced by Bubbletight, LLC ofNeedville, Tex., as would be apparent to one of skill in the art,including fresh-water reactive composite metal, ambient-temperaturefresh-water reactive composite metal, ambient-temperature fresh-waterreactive elastomeric polymer, and high-strength brine-degradablereactive metal.

Generally speaking, the material of support plate 2121 may be configuredto react. The time to react from start to finish (i.e., to the pointwhere the support plate no longer has a durable engagement with thewedge mandrel—compare 22C with 22D) may be in the range of about 3 hoursto about 48 hours.

The support plate 2121 may be configured to include one or more holes2134 formed therein. Although not meant to be limited to any particularnumber, shape, orientation, or size, the holes 2134 may be longitudinalin orientation through the plate 2121. The presence of one or more holes2134 may result in the surface(s) of the support plate 2121 havinggreater exposure to the fluid that promotes reactivity of the material.One or more holes 2134 may extend entirely through the ball seat insert.However, other holes 2134 may only extend to a certain depth. The holes2134 may be optimized to promote the most surface contact, yet at thesame time not detract from the durability of the support plate 2121.

The support plate 2121 may have a plate hollow or bore 2138, which maybe suitable for the adapter shaft (2153) to fit and engage therein.Accordingly, the support plate 2121 may have a set of plate threads2124. The plate threads 2124 may be configured to mate withcorresponding threads (i.e., 2156) of the elongated setting tool adaptershaft 2153. Although not meant to be limited, the threads 2124 may beshear threads.

The body of the support plate may include one or more protruding memberor dogs 2120. As shown there may be about three dogs 2120. An upholeside 2109 of the dogs may be engaged with an end of a fingered member(see FIG. 22B, end 2174 a engaged with uphole side 2109).

Referring now to FIGS. 21A and 21B together, an isometric view and alongitudinal side view of a lower sleeve usable with a downhole tool, inaccordance with embodiments disclosed herein, are shown. The lowersleeve 2160 may be a generally round shaped component configured forengagement into the wedge mandrel (2114). The lower sleeve 2160 may bemade of filament wound composite material. In other embodiments, thelower sleeve 2160 may be made of a reactive material, such as thatdescribed herein.

The lower sleeve 2160 may be in threaded engagement with the mandrel 214by virtue of the coupling of mandrel threads (2117) and sleeve threads2162. The lower sleeve 2160 may have one or more tapered surfaces 361,361A which may reduce chances of hang up on other tools. The lowersleeve 360 may also have an angled sleeve end 363 in engagement with,for example, the first slip (234, FIG. 2C).

Although not shown here, one or more anchor pins may be disposed orsecurely positioned laterally through the lower sleeve 2160 and intoengagement with the wedge mandrel. In an embodiment, brass set screwsmay be used. Pins (or screws, etc.) may prevent shearing or spin offduring drilling.

Referring now to FIGS. 22A, 22B, 22C, and 22D together, a longitudinalcross-sectional view of a system having downhole tool run to a locationwithin a tubular, a longitudinal side cross-sectional view of thedownhole tool of FIG. 22A moved to a set position, a longitudinal sidecross-sectional view of the downhole tool of FIG. 22A set in a tubularand separated from a workstring, and a longitudinal side cross-sectionalview of a the downhole tool of FIG. 22A having various internalcomponents removed therefrom, respectively, in accordance withembodiments disclosed herein, are shown.

System 2100 may include a wellbore 2106 formed in a subterraneanformation with a tubular 2108 disposed therein. A workstring 2112 (shownonly partially here and with a general representation, and which mayinclude a part of a setting tool or device coupled with adapter 2152)may be used to position or run the downhole tool 2102 into and throughthe wellbore 2106 to a desired location.

The downhole tool 2102 may be configured, assembled, run, set, andusable in a similar manner to tool embodiments described herein and inother embodiments (such as in System 200, and so forth), and asotherwise understood to one of skill in the art. Components of thedownhole tool 2102 may be arranged and disposed about a wedge mandrel2114, as described herein and comparable to other embodiments, and asotherwise understood to one of skill in the art. Thus, downhole tool2102 may be comparable or identical in aspects, function, operation,components, etc. as that of other tool embodiments disclosed herein.

The wedge mandrel 2114 may be made of a material as described herein andin accordance with embodiments of the disclosure, such as a compositefilament wound material made by the Applicant. The wedge mandrel 2114may be made other materials, such as a metallic material, for example,an aluminum-based, magnesium-based, or aluminum-magnesium-basedmaterial. The metallic material may be reactive, such as dissolvable,which is to say under certain conditions that wedge mandrel 2114 maybegin to dissolve, and thus alleviating the need for drill thru. Justthe same, the wedge mandrel may be made of reactive composite materialformed from an initial mixture composition of embodiments herein.

Downhole tool 2102 may include a lower sleeve 2160 disposed around thewedge mandrel 2114. The lower sleeve 2160 may be threadingly engagedwith the mandrel 2114. As a support platform 2121 is pulled in tension,various components disposed about mandrel 2114 between the supportplatform 2121 and a setting sleeve (2154, FIG. 22A) may begin tocompress against one another. This force and resultant movement mayultimately cause compression and expansion of a seal element 2122.

Additional tension or load may be applied to the tool 2102 that resultsin movement of the wedge mandrel 2114 against a fingered member 2176.Accordingly, via interaction with angled surfaces of each other, one ormore ends 2175 of the fingered member 2176 may be urged radially outwardand into engagement with tubular 2108. The fingered member 2176 may bemovingly (such as slidingly) engaged and disposed around the wedgemandrel 2114.

The setting sleeve 2154 may engage against a shoulder 2184 of the wedgemandrel 2114, which may accommodate to or provide ability for thetransfer load through the rest of the tool 2102. The setting sleeve maybe a grooved setting sleeve in accordance with embodiments herein.

Although many configurations are possible, the fingered member 2176 maygenerally have a circular body (or ring shaped) portion 2195 configuredfor positioning on or disposal around the wedge mandrel 2114. Extendingfrom the circular body portion may be two or more fingers (dogs,protruding members, etc.) 2177. In the assembled tool configuration, thefingers 2177 may be referred to as facing “uphole” or toward the top(proximate end) of the tool 2102.

The fingered member 2176 may include a plurality of fingers 2177. Inembodiments, there may be a range of about 6 to about 12 fingers 2177.The fingers 2177 may be configured symmetrically and equidistantly toeach other. As the fingers 2177 are urged outwardly they may provide asynergistic effect of centralizing the downhole tool 2102, which may beof greater benefit in situations where the surrounding tubular has ahorizontal orientation.

During setting, the fingered member 2176 (including fingers 2177, withrespective underside 2197) may be urged along a proximate surface 2149(or vice versa, the proximate surface 2149 may be urged against anunderside of the fingered member 2176). The proximate surface 2149 maybe an angled surface or taper of wedge mandrel 2114. Other componentsmay be positioned proximate to the underside (or end 2175) of fingeredmember 2175, such as an insert 2199. As the fingered member 2176 and thesurface 2149 are urged together, the fingers 2177 may be resultantlyurged radially outward toward the inner surface of the tubular 2108. Oneor more ends 2175 of corresponding fingers 2177 may eventually come intocontact with the tubular (such as at contact point 2186). Ends 2175 (offingers) may be configured (such as by machining) with an end taper. Theends 2175 of the fingers 2177 may have surface area contact with thetubular 2108, as illustrated by a length 2189 of contact surfaces(proximate to contact point 2186).

The surface 2149 may be smooth and conical in nature, which may resultin smooth, linear engagement with the fingered member 2176. The angledsurface 2149 may transition to a more or less axial surface 2149 a(i.e., a surface that is about parallel to a longitudinal axis 2158).

In aspects, the outer surface of the wedge mandrel 2114 may beconfigured with a detent (or notch) 2170, approximately at thetransition point from angled surface 2149 to axial surface 2149 a. Inthe assembled position, the ends 2175 of the fingers 2177 may reside orbe positioned within or proximate to the detent 2170. The arrangement ofthe ends 2175 within the detent 2170 may prevent inadvertent operationof the fingered member 2176. In this respect, a certain amount ofsetting force is required to “bump” the ends of the fingers 2177 out ofand free of the detent 2170 so that the fingered member 2176 and thesurface 2149 can be urged together, and the fingers 2177 extendedoutwardly. As shown, the insert 2199 may be directly proximate to thedetent 2170, and thus inbetween the detent 2170 and the finger ends2177. In this respect, a certain amount of setting force is required to“bump” the insert 2199 out of and free of the detent 2170 so that it maybe urged along the surface 2149.

The fingered member 2176 may be referred to as having a “transitionzone” 2110, essentially being the part of the member where the fingers2177 begin to extend away from the body 2195. In this respect, thefingers 2177 are connected to or integral with the body 2195. Inoperation as the fingers 2177 are urged radially outward, a flexing (orpartial break or fracture) may occur within the transition zone 2110.The transition zone 2110 may include an outer surface 2137 and innersurface 2129. The outer surface 2137 and inner surface 2129 may beseparated by a portion or amount of material 2185. The fingered member2176 may be configured so that the flexing, break or fracture occurswithin the material 2185. Flexing or fracture may be induced within thematerial as a result of one or more grooves. For example, the innersurface 2137 may have a first finger groove 2111. The outer surface 2137may in addition or alternatively have a finger groove, such as a secondfinger groove 2113.

The presence of the material 2185 may provide a natural “hinge” effectwhereby the fingers 2177 become moveable from the body (ring) 2195, suchas when the fingered member 2176 is urged against surface 2149. Aftersetting one or more fingers 2177 may remain at least partially connectedwith body 2195 in the transition zone 2110. The presence of the material2185 may promote uniform flexing of the fingers 2177. The length of thefingers 2177 and/or amount of material 2185 are operational variablesthat may be modified to suit a particular need for a respective annulussize.

As shown in the Figures, the downhole tool 2102 may include othercomponents, such as the seal element 2122. The seal element 2122 may bemade of an elastomeric and/or poly material, such as rubber, nitrilerubber, Viton or polyurethane, and may be configured for positioning orotherwise disposed around the wedge mandrel 2114. The seal element 2122may have an inner circumferential groove 2123. The presence of thegroove 2123 may assist the seal element 2122 to initially buckle uponstart of the setting sequence. The groove 2123 may have a size (e.g.,width, depth, etc.) of about 0.25 inches.

On either side of the seal element may be a backup ring. As shown theremay be a first backup ring 2157 a and a second backup ring 2157 b. Inthe assembled configuration, the insert 2199 may be positioned betweenthe ends 2175 of the fingers 2177 and the second backup ring 2157 b.

The fingers 2177 may have a respective gripper insert 2191 fitted orotherwise disposed therein. Although not limited to any particularnumber, type or size, there may be a respective gripper insert 2191disposed in the finger(s) 2177. The gripper insert 2191 may bepositioned within a window (or hole, opening, etc.) formed in anyrespective finger 2177. In this respect, the gripper insert 2191 may bepositioned therein, wherein its underside may be proximate to the wedgemandrel outer surface.

The fingered member 2175 may have one or more recessed regions (or hole,opening, etc.) to accommodate respective dogs 2120 of the supportplatform 2121. Similarly, the wedge mandrel 2114 may have one or moremandrel windows 2119 also to accommodate respective dogs 2120 of thesupport platform.

Components of the downhole tool 2102 may be arranged and disposed aboutthe wedge mandrel 2114, as described herein and in other embodiments,and as otherwise understood to one of skill in the art. Thus, downholetool 2102 may be comparable or identical in aspects, function,operation, components, etc. as that of other tool embodiments providedfor herein, and redundant discussion is limited for sake of brevity,while structural (and functional) differences are discussed in withdetail, albeit in a non-limiting manner.

The tool 2102 may be deployed and set with a conventional setting tool(not shown) such as a Model 10, 20 or E-4 Setting Tool available fromBaker Oil Tools, Inc., Houston, Tex. Once the tool 2102 reaches the setposition within the tubular, the setting mechanism or workstring may bedetached from the tool 2102 by various methods, resulting in the tool2102 left in the surrounding tubular and one or more sections of thewellbore isolated.

Once the tool 2102 reaches the set position within the tubular 2108, thesetting mechanism or workstring 2112 may be detached from the tool 2102by various methods, resulting in the tool 2102 left in the surroundingtubular, whereby one or more sections of the wellbore may be isolated.

In an embodiment, once the tool 2102 is set, tension may be furtherapplied to the setting tool/adapter 2152 until the elongated stud 2153is detached from the support platform 2120. The amount of load appliedto the adapter 2152 may cause separation (disconnect via tensilefailure) in the range of about, for example, 20,000 to 40,000 poundsforce. The load may be about 25,000 to 30,000 pounds force. In otherapplications, the load may be in the range of less than about 10,000pounds force.

The adapter 2152 may include the stud 2153 configured with the threadsthereon. In an embodiment, the stud may have external (male) threads andthe wedge mandrel 2114 may have internal (female) threads; however, typeor configuration of threads is not meant to be limited, and could be,for example, a vice versa female-male connection, respectively. Theadapter 2152 may be made of a durable material, such as a metal or alloylike 4140 steel alloy. Although not necessary, there may be an adapterport 2153 a within the stud 2153, which may be useful to providepressure equalization. The stud 2153 may have a lateral (outer) diametersuitable enough for passing through bores 2138, 2139. In aspects, thelateral diameter may be about 1 inch. The lateral diameter may be in therange of about 0.5 inches to about 1.5 inches. The bores 2138, 2139 mayhave a comparable inner diameter.

Accordingly, the adapter 2152 may separate or detach from the downholetool 2102, resulting in the workstring 2112 being able to separate fromthe tool 2102, which may be at a predetermined moment. The loadsprovided herein are non-limiting and are merely exemplary. The settingforce may be determined by specifically designing the interactingsurfaces of the tool and the respective tool surface angles.

Referring briefly to FIG. 22E, a close-up side cross-sectional view ofan alternative adapter connection to a downhole tool, in accordance withembodiments of the disclosure, is shown. As shown, stud 2153 mayalternatively connect to a lower ring 2121 a. In this respect, the stud2153 may pass through a bore 2138 of a support plate 2121 (instead ofengaging therewith) and instead threadingly engage into the lower ring2121 a. The lower ring 2121 a may be made of filament wound compositematerial, which may be configured with shear threads. This type ofconfiguration may be useful for predictability of shearing versus thatof shearing from the metal support plate 2121.

Referring again to 22A-22D, the downhole tool 2102 may include the wedgemandrel 2114 configured with a bore 2151, and a respective inner boresurface 2147. The inner surface 2147 may include one or more threadedsurfaces formed thereon. As such, there may be a first set of threads2116 configured for coupling the wedge mandrel 2114 with correspondingthreads 2145 of a ball seat insert 2135. Although not meant to belimited, each of these threads may be rounded threads.

The ball seat insert 2135 may be made of a material of embodimentsherein, such as a reactive material (which may be metallic or plastic innature). The ball seat insert 2135 may be configured to include one ormore holes 2130 formed therein. Although not meant to be limited to anyparticular number, shape, orientation, or size, the holes 2130 may belongitudinal in orientation through the insert 2135. The presence of oneor more holes 2130 may result in the surface(s) of the insert 2135having greater exposure to the fluid that promotes reactivity of thematerial. One or more holes 2130 may extend entirely through the ballseat insert. However, other holes 2130 may only extend to a certaindepth.

The ball seat insert 2135 may have an insert hollow or bore 2139, whichmay be suitable for the adapter shaft 2153 to pass therethrough. Thewider end of the insert 2135 may have an insert groove, which may begenerally circumferential in nature. The insert groove may be suitablefor fitting an o-ring 2179 therein.

The insert 2135 may be configured with a ball seat surface 2159 suchthat a drop ball may come to rest and seat at in the seat. Asapplicable, the drop ball (not shown here) may be lowered into thewellbore and flowed toward the drop ball seat 2159. Alternatively, theball may be held within the tool during run-in, thus alleviating theneed for flowdown. The ball seat 2159 may be formed with a radius (i.e.,circumferential rounded edge or surface).

The downhole tool 2102 may be run into wellbore to a desired depth orposition by way of the workstring 2112 that may be configured with thesetting device or mechanism. The workstring 2112 and setting sleeve 2154may be part of the system 2100 utilized to run the downhole tool 2102into the wellbore, and activate the tool 2102 to move from an unset(e.g., 21A) to set position (e.g., 21C). Although not meant to belimited to any particular type or configuration, the setting sleeve 2154may be like of that other embodiments disclosed herein, such as that ofFIGS. 11A-11C. Briefly, FIG. 21B illustrates how compression of a sleeveend 2155 with a should end 2184 of the wedge mandrel 2114 may occur atthe beginning of the setting sequence, whereby subsequently tension mayincrease through the tool 2102.

Although not shown here, the downhole tool 2102 may include ananti-rotation assembly that includes an anti-rotation device ormechanism (e.g., see 282, FIGS. 2C and 2D, and related text), which maybe a spring, a mechanically spring-energized composite tubular member,and so forth. The device may be configured and usable for the preventionof undesired or inadvertent movement or unwinding of the tool 2102components.

On occasion it may be necessary or otherwise desired to produce a fluidfrom the formation while leaving a set plug in place. However, an innerdiameter (ID) of a bore (e.g., 250, FIG. 2D) in a mandrel (214) may betoo narrow to effectively and efficiently produce the fluid—thus inembodiments it may be desirous to have an oversized ID 2131 through thetool 2102. The ID of a conventional bore size is normally adequate toallow drop balls to pass therethrough, but may be inadequate forproduction. In order to produce desired fluid flow, it often becomesnecessary to drill out a set tool—this requires a stop in operations,rig time, drill time, and related operator and equipment costs.

On the other hand, the presence of the oversized ID 2131 of bore 2151,and thus a larger cross-sectional area as compared to bore 250, provideseffective and efficient production capability through the tool 2102without the need to resort to drilling of the tool. However, a reducedwall thickness 2127 of mandrel 2114 may be problematic to thecharacteristics of the tool 2102, especially during the settingsequence. This may especially be the case for composite material.

As a large bore 2151 may result in reduced wall thickness 2127, this mayin turn reduce tensile strength and collapse strength. As such thedownhole tool 2102 may be configured in a manner to withstand thesetting sequence, but yet be able to provide the oversized ID 2131.

In accordance with the disclosure, components of tool 2102 may be madeof reactive materials (e.g., materials suitable for and are known todissolve in downhole environments [including extreme pressure,temperature, fluid properties, etc.] after a brief or limited period oftime (predetermined or otherwise) as may be desired). In an embodiment,a component made of a reactive material may begin to dissolve withinabout 3 to about 48 hours after setting of the downhole tool.

In aspects, the wedge mandrel 2114 may be made a material made from acomposition described herein. The wedge mandrel 2114 may be made of amaterial that is adequate to provide durability and strength to the tool2102 for a sufficient amount of time that includes run-in, setting andfrac.

The downhole tool 2102 may include the wedge mandrel 2114 extendingthrough the tool (or tool body) 2102, such that other components of thetool 2102 may be disposed therearound. The wedge mandrel 2114 mayinclude the flowpath or bore 2151 formed therein (e.g., an axial bore).The bore 2151 may extend partially or for a short distance through themandrel 2114, or the bore 2151 may extend through the entire wedgemandrel 2114, with an opening at its proximate end 2148 and oppositelyat its distal end 2146.

The presence of the bore or other flowpath through the wedge mandrel2114 may indirectly be dictated by operating conditions. That is, inmost instances the tool 2102 may be large enough in outer diameter(e.g., in a range of about 4-5 inches) such that the bore 2151 may becorrespondingly large enough (e.g., 3-4 inches) so that fluid F may beproduced therethrough. One of skill would appreciate these ranges maygenerally be applicable to a 5.5″ casing and that scale may be modifiedfor the tool and any of its components as applicable to changes incasing ID.

As illustrated, the ball seat insert 2135 may be disposed at a depth (orlength, distance, etc.) D from the proximate mandrel end 2148. The depthD may be of a distance whereby the ball seat 2159 may be proximatelyunaligned to where the seal element 2122 is initially positioned, asshown in FIG. 22A.

The location of the ball seat 2159 at depth D may be useful to obtainadditional lateral strength once the ball 2163 rests therein. That is,significant forces are felt by the mandrel during the setting sequence,especially in the area of where the sealing element 2122 is energized,as well as pressure differential between the annulus external to thetool and the bore 2151 (in some instances the differential may be in therange about 10,000 psi). These forces may be transferred laterallythrough the wedge mandrel 2114, and since the mandrel 2114 may have alimited wall thickness 2127, there exists the possibility of collapse;however, the ball 2163, in conjunction with the ball seat insert 2135,may provide added strength and reinforcement in the lateral direction.

FIG. 22C illustrates how, upon setting, the ball 2163 may be urgedagainst the ball seat 2159. In embodiments, a middle region of theenergized sealing element 2122 may be substantially laterally proximateto a middle ball section of the ball 2163. Thus, the seal element 2122may be movable along surface 2149.

The amount of pressure required to urge and wedge the ball 2163 againstthe ball seat 2159 may be predetermined. Thus, the size of the ball 2163(e.g., ball diameter 2132), ball seat 2159, and radius (2159 a) may bedesigned, as applicable.

The ball seat 2159 may be configured in a manner so that when 2163 seatstherein, a flowpath through the wedge mandrel may be closed off (e.g.,flow through the bore is restricted by the presence of the ball). Theball 2163 may be made of a composite material, whereby the ball 2163 maybe capable of holding maximum pressures during downhole operations(e.g., fracing). In aspects, the ball 2163 may be made of a reactivematerial of embodiments herein. FIG. 22A illustrates how the downholetool 2102 may have a ‘ball in place’ configuration, whereby the ball isdisposed within the tool during setup, and thus alleviating the need forflowdown. Upon removable of the shaft 2153 from the insert bore 2139,the ball 2163 will be free to move into the seat 2159.

The support plate 2121 may be a generally round shaped componentconfigured for engagement into the wedge mandrel 2114. During setting,the support plate 2121 will be pulled as a result of its attachment tothe setting tool (via elongated shaft 2153). As the support plate 2121is pulled, the components disposed about the wedge mandrel 2114 andbetween the support plate 2121 and end 2155 of setting sleeve 2154 mayfurther compress against one another.

In embodiments, the support plate 2121 may be made of a material ofembodiments herein, such as a reactive material (which may be metallicor plastic in nature). Generally speaking, the material of support plate2121 may be configured to react. The time to react from start to finish(i.e., to the point where the support plate no longer has a durableengagement with the wedge mandrel 2114 may be in the range of about 3hours to about 48 hours.

The support plate 2121 may be configured to include one or more holes2134 formed therein. Although not meant to be limited to any particularnumber, shape, orientation, or size, the holes 2134 may be longitudinalin orientation through the plate 2121. The presence of one or more holes2134 may result in the surface(s) of the support plate 2121 havinggreater exposure to the fluid that promotes reactivity of the material.One or more holes 2134 may extend entirely through the ball seat insert.However, other holes 2134 may only extend to a certain depth. The holes2134 may be optimized to promote the most surface contact, yet at thesame time not detract from the durability of the support plate 2121.

The support plate 2121 may have a plate hollow or bore 2138, which maybe suitable for the adapter shaft (2153) to fit and engage therein.Accordingly, the support plate 2121 may have a set of plate threads2124. The plate threads 2124 may be configured to mate withcorresponding threads (i.e., 2156) of the elongated setting tool adaptershaft 2153. Although not meant to be limited, the threads 2124 may beshear threads.

The body of the support plate may include one or more protruding memberor dogs 2120. As shown there may be about three dogs 2120. In theassembled configuration, an uphole side 2109 of the dogs 2120 may beengaged with an end surface 2174 a of a downhole end 2173 of thefingered member 2176.

It should be apparent to one of skill in the art that the tool 2102 ofthe present disclosure may be configurable as a frac plug, a drop ballplug, bridge plug, etc. simply by utilizing one of a plurality ofadapters or other optional components. In any configuration, once thetool 2102 is properly set, fluid pressure may be increased in thewellbore 2106, such that further downhole operations, such as fracturein a target zone, may commence.

The downhole tool 2102 may have one or more components made fromdrillable composite material(s), such as glass fiber/epoxy, carbonfiber/epoxy, glass fiber/PEEK, carbon fiber/PEEK, etc. Other resins mayinclude phenolic, polyamide, etc. The downhole tool 2102 may have one ormore components made of non-composite material, such as a metal or metalalloys. The downhole tool 2102 may have one or more components made of areactive material (e.g., dissolvable, degradable, etc.).

Accordingly, components of tool 2102 may be made of non-dissolvablematerials (e.g., materials suitable for and are known to withstanddownhole environments [including extreme pressure, temperature, fluidproperties, etc.] for an extended period of time (predetermined orotherwise) as may be desired).

Just the same, one or more components of a tool of embodiments disclosedherein may be made of a reactive material (e.g., a material suitable forand known to dissolve, degrade, etc. in downhole environments [includingextreme pressure, temperature, fluid properties, etc.] after a brief orlimited period of time (predetermined or otherwise) as may be desired).In an embodiment, a component of the downhole tool made of a reactivematerial may begin to react within about 3 to about 48 hours aftersetting of the downhole tool 2102.

The reactive material may be formed from an initial or starting mixturecomposition that may include about 100 parts by weight base resin systemthat comprises an epoxy with a curing agent (or ‘hardener’). The finalcomposition may be substantially the same as the initial composition,subject to differences from any reaction during curing.

The base resin may be desirably prone to break down in a high tempand/or high pressure aqueous environment. The epoxy may be acycloaliphatic epoxy resin with a low viscosity and a high glasstransition temperature. The epoxy may be characterized by having highadhesability with fibers. As an example, the epoxy may be3,4-epoxycyclohexylmethyl-3′,4′-epoxycyclohexane-carboxylate.

The hardener may be an anhydride, i.e., anhydride-based. For example,the curing agent may be a methyl carboxylic, such asmethyl-5-norborene-2, 3-dicarboxylic anhydride. The hardener mayinclude, and be pre-catalyzed with, an accelerator. The accelerator maybe imidazole-based.

The accelerator may help in saving or reducing the curing time.

The ratio of epoxy to curing agent may be in the range of about 0.5 toabout 1.5. In more particular aspects, the ratio may be about 0.9 toabout 1.0.

Processing conditions of the base resin system may include multiplestages of curing.

The composition may include an additive comprising a clay. The additivemay be a solid in granular or powder form. The additive may be about 0to about 30 parts by weight of the composition of amontmorillonite-based clay. In aspects, the clay may be about 0 to about20 parts by weight of the composition. The additive may be anorganophilic clay.

An example of a suitable clay additive may be CLAYTONE® APA by BYKAdditives, Inc.

The composition may include a glass, such as glass bubbles or spheres(including microspheres and/or nanospheres). The glass may be about 0 toabout 20 parts by weight of the composition. In aspects, the glass maybe about 5 to about 15 parts by weight of the composition.

An example of a suitable glass may be 3M Glass Bubbles 342XHS by 3M.

The composition may include a fiber. The fiber may be organic. The fibermay be a water-soluble fiber. The fiber may be in the range of about 0to about 30 parts by weight of the composition. In aspects, the fibermay be in the range of about 15 to about 25 parts by weight.

The fiber may be made of a sodium polyacrylate-based material. The fibermay resemble a thread or string shape. In aspects, the fiber may have afiber length in the range of about 0.1 mm to about 2 mm. The fiberlength may be in the range of about 0.5 mm to about 1 mm. The fiberlength may be in the range of substantially 0 mm to about 6 mm.

The fiber may be a soluble fiber like EVANESCE water soluble fiber fromTechnical Absorbents Ltd.

The composition is subjected to curing in order to yield a finalizedproduct. A device of the disclosure may be formed during the curingprocess, or subsequently thereafter. The composition may be cured with acuring process of the present disclosure.

In other embodiments, components may be made of a material that may havebrittle characteristics under certain conditions. In yet otherembodiments, components may be made of a material that may havedisassociatable characteristics under certain conditions.

One of skill in the art would appreciate that the material may be thesame material and have the same composition, but that the physicalcharacteristic of the material may change, and thus depend on variablessuch as curing procedures or downhole conditions.

The material may be a resin. The resin may be an anhydride-cured epoxymaterial. It may be possible to use sodium polyacrylate fiber inconjunction therewith, although any fiber that has dissolvableproperties associated with it

Advantages

Embodiments herein provide for the ability to produce fluids, such aswater, oil, other hydrocarbons, gaseous or liquidous, without having todrill out or remove an isolation tool. This saves time, reduces cost,and allows production to commence, without having to wait on a rig.

Embodiments of the downhole tool are smaller in size, which allows thetool to be used in slimmer bore diameters. Smaller in size also meansthere is a lower material cost per tool. Because isolation tools, suchas plugs, are used in vast numbers, and are generally not reusable, asmall cost savings per tool results in enormous annual capital costsavings.

A synergistic effect is realized because a smaller tool means fasterdrilling time is easily achieved. Again, even a small savings indrill-through time per single tool results in an enormous savings on anannual basis.

Advantageously, the configuration of components, and the resilientbarrier formed by way of the composite member results in a tool that canwithstand significantly higher pressures. The ability to handle higherwellbore pressure results in operators being able to drill deeper andlonger wellbores, as well as greater frac fluid pressure. The ability tohave a longer wellbore and increased reservoir fracture results insignificantly greater production.

Embodiments of the disclosure provide for the ability to remove theworkstring faster and more efficiently by reducing hydraulic drag.

As the tool may be smaller (shorter), the tool may navigate shorterradius bends in well tubulars without hanging up and presetting. Passagethrough shorter tool has lower hydraulic resistance and can thereforeaccommodate higher fluid flow rates at lower pressure drop. The tool mayaccommodate a larger pressure spike (ball spike) when the ball seats.

The composite member may beneficially inflate or umbrella, which aids inrun-in during pump down, thus reducing the required pump down fluidvolume. This constitutes a savings of water and reduces the costsassociated with treating/disposing recovered fluids.

One piece slips assembly may be resistant to preset due to axial andradial impact allowing for faster pump down speed. This further reducesthe amount of time/water required to complete frac operations.

While preferred embodiments of the disclosure have been shown anddescribed, modifications thereof can be made by one skilled in the artwithout departing from the spirit and teachings of the disclosure. Theembodiments described herein are exemplary only, and are not intended tobe limiting. Many variations and modifications of embodiments disclosedherein are possible and are within the scope of the disclosure. Wherenumerical ranges or limitations are expressly stated, such expressranges or limitations should be understood to include iterative rangesor limitations of like magnitude falling within the expressly statedranges or limitations. The use of the term “optionally” with respect toany element of a claim is intended to mean that the subject element isrequired, or alternatively, is not required. Both alternatives areintended to be within the scope of the claim. Use of broader terms suchas comprises, includes, having, etc. should be understood to providesupport for narrower terms such as consisting of, consisting essentiallyof, comprised substantially of, and the like.

Accordingly, the scope of protection is not limited by the descriptionset out above but is only limited by the claims which follow, that scopeincluding all equivalents of the subject matter of the claims. Each andevery claim is incorporated into the specification as an embodiment ofthe present disclosure. Thus, the claims are a further description andare an addition to the preferred embodiments of the present disclosure.The inclusion or discussion of a reference is not an admission that itis prior art to the present disclosure, especially any reference thatmay have a publication date after the priority date of this application.The disclosures of all patents, patent applications, and publicationscited herein are hereby incorporated by reference, to the extent theyprovide background knowledge; or exemplary, procedural or other detailssupplementary to those set forth herein.

What is claimed is:
 1. A downhole tool suitable for use in a wellbore,the tool comprising: a wedge mandrel further comprising: a distal end; aproximate end; an outer surface; an inner flowbore extending through thewedge mandrel; a first set of threads on the inner flowbore at thedistal end; a fingered member disposed around the wedge mandrel; a sealelement disposed around the wedge mandrel; a ball seat insert disposedin the inner flowbore and engaged with the first set of threads; asupport platform disposed in the inner flowbore and engaged with thewedge mandrel; and a lower sleeve disposed around and engaged with theouter surface of wedge mandrel at the distal end, wherein the wedgemandrel further comprises a plurality of lateral windows configured fora plurality of respective support platform dogs to movingly engagetherein.
 2. The downhole tool of claim 1, wherein the fingered memberalso comprises a plurality of recessed regions configured for theplurality of respective support platform dogs to engage therein.
 3. Thedownhole tool of claim 2, wherein the wedge mandrel further comprises aninner flowbore diameter in an inner bore diameter range of 1.5 inches to4 inches.
 4. The downhole tool of claim 1, wherein the wedge mandrelfurther comprises an inner flowbore diameter in an inner bore diameterrange of 1.5 inches to 4 inches, wherein the ball seat insert comprisesa ball seat formed therein, and a ball seat bore having an innerdiameter in a seat bore range of 0.5 inches to 1.5 inches.
 5. Thedownhole tool of claim 4, wherein upon setting of the downhole tool andpressurization via a ball positioned in the ball seat, a middle of theball is laterally proximate to a middle of the seal element.
 6. Thedownhole tool of claim 1, wherein an at least one or more components ofthe downhole tool is made of a cured reactive material formed from aninitial mixture composition comprising: a cycloaliphatic epoxy resin andan anhydride curing agent.
 7. The downhole tool of claim 1, the downholetool further comprising: a first backup ring engaged with a first sideof the seal element; a second backup ring engaged with a second side ofthe seal element, and wherein the fingered member further comprises: acircular body; a plurality of fingers extending from the circular body;and a longitudinal gap formed between respective fingers.
 8. Thedownhole tool of claim 1, wherein the wedge mandrel comprises a firstouter diameter at the distal end, a second outer diameter at theproximate end, and wherein an at least one or more components of thedownhole tool is made of a cured reactive material formed from aninitial mixture composition comprising: a cycloaliphatic epoxy resin andan anhydride curing agent.
 9. The downhole tool of claim 1, wherein thefingered member is made of composite filament wound material, andfurther comprises: a circular body; and a plurality of fingers extendingfrom the circular body, at least one of the plurality of fingerscomprising a gripper insert disposed therein.
 10. The downhole tool ofclaim 9, wherein the gripper insert is made of metal.
 11. A downholetool for use in a wellbore, the tool comprising: a wedge mandrel furthercomprising: a distal end; a proximate end; an outer mandrel surface; anda flowbore forming an inner mandrel surface, and extending through thewedge mandrel; a fingered member disposed around the wedge mandrel; aseal element disposed around the wedge mandrel; a support platformdisposed in the flowbore at the distal end, and engaged with the innermandrel surface; and a lower sleeve disposed around and engaged with theouter mandrel surface at the distal end, wherein the wedge mandrelfurther comprises a plurality of lateral windows configured for aplurality of respective support platform dogs to movingly engagetherein, and wherein the fingered member also comprises a plurality ofrecessed regions configured for the plurality of respective supportplatform dogs to engage therein.
 12. The downhole tool of claim 11, thedownhole tool further comprising: an insert positioned between thefingered member and the seal element, and in proximity with an end ofthe fingered member; and a ball seat insert disposed in the flowbore atthe proximate end, and engaged with an inner surface of the flowbore.13. The downhole tool of claim 12, wherein the flowbore comprises aninner flowbore diameter in the range of at least 1.5 inches to no morethan 4 inches, and wherein the ball seat insert comprises a ball seatformed therein, and a ball seat bore having an inner ball seat borediameter in the range of at least 0.5 inches to no more than 1.5 inches.14. The downhole tool of claim 12, wherein upon setting of the downholetool and pressurization via a ball positioned in the ball seat, a middleof the ball is laterally proximate to a middle of the seal element. 15.The downhole tool of claim 11, the downhole tool further comprising: afirst backup ring engaged with a first side of the seal element; asecond backup ring engaged with a second side of the seal element,wherein the fingered member further comprises: a circular body; aplurality of fingers extending from the circular body; a longitudinalgap formed between respective fingers; and a transition zone between thecircular body and the plurality of fingers, wherein the transition zonefurther comprises an inner member surface and an outer member surface,wherein the inner member surface comprises a first inner member groove,and wherein the outer member surface comprises a first outer membergroove.
 16. The downhole tool of claim 11, wherein at least one or morecomponents of the downhole tool is made of a cured reactive materialformed from an initial mixture composition comprising: a cycloaliphaticepoxy resin; and an anhydride curing agent.
 17. The downhole tool ofclaim 11, wherein the wedge mandrel comprises a first outer diameter atthe distal end, a second outer diameter at the proximate end, whereinthe outer surface comprises an axially linear surface, and an axiallyangled surface and a detent formed therebetween, and wherein the secondouter diameter is larger than the first outer diameter.
 18. The downholetool of claim 17, wherein the fingered member is made of compositefilament wound material, and further comprises: a circular body; and aplurality of fingers extending from the circular body, at least one ofthe plurality of fingers comprising a gripper insert disposed therein.19. The downhole tool of claim 18, wherein the gripper insert is made ofmetal, wherein the insert comprises a circular body, a first end, asecond end, and a helical winding groove formed in the circular bodybetween the first end and the second end.
 20. A method of operating adownhole tool in order to isolate one or more sections of a wellbore,the method comprising: using a workstring to run the downhole tool intothe wellbore to a desired position, the downhole tool comprising: awedge mandrel further comprising: a distal end; a proximate end; anouter surface; and a flowbore extending through the wedge mandrel; afingered member disposed around the wedge mandrel; a seal elementdisposed around the wedge mandrel; a ball seat insert disposed in theflowbore at the proximate end, and engaged with an inner surface of theflowbore; a support platform disposed in the flowbore; and a lowersleeve disposed around and engaged with the outer surface of wedgemandrel at the distal end; wherein the wedge mandrel further comprises aplurality of lateral windows configured for a plurality of respectivesupport platform dogs to movingly engage therein; actuating a settingdevice coupled with the downhole tool in order to set the downhole toolinto at least partial engagement with a surrounding tubular;disconnecting the downhole tool from the setting device coupledtherewith when the tensile load is sufficient to cause separationtherefrom; and seating a ball in a ball seat of the ball seat insert.